From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov> 

Sent: Friday, July 17, 2015 4:22 PM 

To: Harvey, Reid; Culligan, Kevin; Vasu, Amy 

Cc: Szabo, Aaron; Grossman, Andrea 

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- Clean Power 

Plan and Federal Implementation Plan 

Attached are two summaries of interagency comments under EO 12866 and 13563. The first 

attachment contains a summary of interagency comments provided on the July 2nd version of the 

Clean Power Plan draft final rule. 

 

The second attachment contains a summary on interagency comments provided on the Federal 

Plan rule. 

Thanks and please let me know if you have any questions. 

Nathan 

<< SummaryofinteragencycommentsunderEO12866_13563_EO 12866_CPP 2060 AR33 

Final_2015_7_17.docx >> 

<< SummaryofInteragencyCommentsUnderEO12866_13563_Federal 

PlanNPRM_7172015.docx >> ** 

** File not included in this item; see Docket ID No. EPA-HQ-OAR-2015-0199 for a copy of this file. 
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6560-50

EO 12866_CPP 2060 AR33 Final_20150702 

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 

based on the best system of emission reduction (BSER) for two 

subcategories of existing fossil fuel-fired EGUs, fossil fuelfired 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 
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progress already underway in the U.S. to reduce CO2 emissions 

from the utility power sector. 

DATES: The final rule is effective on [INSERT THE DATE 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.
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World Wide Web. In addition to being available in the 

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

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

final rule will be posted at the following address: 

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

relevant to this rulemaking, including technical support 

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

the following terms and acronyms are defined as follows: 

ACEEE American Council for an Energy Efficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and Congress of 

Industrial Organizations 

ASTM American Society for Testing 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 

ERC Emission Rate Credit 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt 

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

LBNL Lawrence Berkeley National Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 

MWh Megawatt-hour 
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NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

Commissioners 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

OMB Office of Management and Budget 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission Organization 

SBA Small Business Administration 

SBC System Benefits Charge 

SCC Social Cost of Carbon 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

Tg Teragram (one trillion (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate 

Change 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Executive Summary 

B. Organization and Approach for this Final Rule 
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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 

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. Timeline for State Plan Performance and Provisions to 

Encourage Early Action 

C. State Plan Approaches 

D. State Plan Components and Approvability Criteria 
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E. State Plan Submittal and Approval Process and Timing 

F. State Plan Performance Demonstrations 

G. Additional Considerations for State Plans 

H. Resources for States to Consider in Developing Plans 

I. Considerations for CO2 Emission Reduction 

 Measures that Occur at Affected EGUs 

J. Additional Considerations and Requirements for Mass-Based 

State Plans 

K. Additional Considerations and Requirements for Rate-Based 

State Plans 

J. Treatment of Interstate Effects and Leakage 

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 

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 
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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 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 

emission 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 
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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 be required to develop and implement 

plans that set emission standards equal to the emission 

performance rates or that 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 

 

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 standard and a 

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

EPA determines that such a plan is necessary or appropriate, it 

has the responsibility to establish CAA section 111(d) plans for 

areas of Indian country where affected sources are located 

unless a tribe on whose lands an affected source (or sources) is 

located seeks and obtains authority from the EPA to develop and 

implement a CAA section 111(d) plan, pursuant to the 40 CFR 49.9

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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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 

recognizes that successfully achieving reductions by 2022 will 

require actions by states and utilities that lead to some CO2

emission reductions prior to 2022. Therefore, the EPA is 

requiring states to demonstrate that they are taking actions 

that will ensure that emission reductions from affected EGUs 

begin no later than 2022. Periodic state-level demonstrations 

during the 2022-2029 period will ensure that required CO2

emission reductions are being accomplished and that no 

inadvertent increases are occurring. 

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 

major provisions of the final rule, the estimated CO2 emission 

Commented [A1]: The fact that states can set their own glide 

paths would seem to enable states to begin with BAU in 2022 (or 

even be higher than BAU in 2022) and go deeper later – so perhaps 

the requirement is that performance standards apply to sources no 

later than the beginning of 2022? 

Formatted: Highlight

Commented [A2]: It’s not entirely clear what the connection is 

between this sentence and the following, or that there will 

necessarily be actions taken before 2022 that will lead to emission 

reductions—a topic likely to be of great focus during the stay 

litigation. 

Formatted: Highlight
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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. 

Concurrent with this action, the EPA is also issuing a 

final rule that establishes CO2 emission standards for new, 
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modified, and reconstructed power plants. Together, these rules 

ensure that the utility power sector in the U.S. can continue to 

supply reliable and affordable electricity to all Americans 

using a diverse fuel supply while reducing CO2 emissions by a 

substantial amount. As with past EPA rules addressing air 

pollution from the utility power sector, these guidelines have 

been designed with a clear recognition of the unique features of 

this sector. The agency recognizes that utilities provide an 

essential public service and are regulated and managed in ways 

unlike almost any other industrial activity. This final rule 

takes that into account in providing assurances for continued 

reliable, affordable electricity. 

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 CO2 emission 

reductions. States will play a key role in ensuring that 

emission reductions are achieved at a reasonable cost. States 

will have the flexibility to choose from a range of plan 

Deleted: tht
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approaches and measures, including numerous measures beyond 

those considered in setting the emission performance rates, and 

this final rule allows and encourages states to choose 

effective, lower cost solutions. 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 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) 

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, 

 

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

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

climateactionplan.pdf 
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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: 

the building block approach for the BSER; state-specific, rather 

than source-specific goals; a 10-year interim goal that could be 

met “on average” over the 10-year period between 2020 and 2029; 

and a “portfolio” option for state plans. These features were 

intended to maximize the range of choices that states and 

utilities could select in order to achieve their emission 

limitations at low cost while ensuring electric system 

reliability. The building block approach is a key feature of the 
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proposal that we are retaining in the final rule. 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. In response to the EPA’s broad request 

for comment on all elements of the proposal, the EPA received 

many thoughtful comments. The final guidelines continue to 

embrace the basic approach of the proposal, 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 
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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 

commissioners, system operators, owners and operators of every 

type of power generating facility, other industry 

representatives, labor leaders, public interest advocates, 

community leaders, and members of the public. 

As a result, these final emission guidelines reflect 

modifications that build on the proposal and the alternatives 

on which we sought comment, and 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 consultation with federal, state and regional 

energy agencies and authorities, to ensure that the actions 
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sources will take to reduce GHG emissions will not compromise 

electric system reliability or affordability of the U.S. 

electricity supply. Input and assistance from the Federal Energy 

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

(DOE) has been particularly important in shaping these final 

guidelines. 

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 

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 
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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 traditional 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, 5) source-specific CO2 emission performance rates that 

are uniform across the two fossil fuel-fired subcategories 

covered in these guidelines, 6) a variation on the proposal’s 

“portfolio” option for state plans – called the “state 

measures” approach - that continues to provide states 

flexibility while ensuring that all state plans have federally 

enforceable measures as a backstop, 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 combination of 

provisions expressly designed to ensure electric system 

reliability, 
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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 FERC and DOE. We provide a high level 

explanation in the following paragraphs and provide greater 

detail about all of these changes in later sections of this 

preamble and associated documents. 

Interim Period Start Date of 2022 and a Gradual Glide Path 

The start date and trajectory of emission reduction 

requirements in the interim period was the subject of 

significant comment. Earlier this year, FERC conducted a series 

of technical conferences comprising one national session and 

three regional sessions. The information provided by workshop 

participants echoed much of the material that had been submitted 

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

FERC Commissioners, drawing upon information highlighted at the 

technical conferences, transmitted to the EPA some suggestions 

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

utilities, and reliability entities asked us to ensure adequate 

time for states, utilities, and grid operators to implement 

strategies to achieve CO2 reductions. They expressed concern 

that, in the proposal, at least some states would be required 
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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 

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

record, as well as other information sources, made it clear that 
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providing sufficient time for planning and implementation was 

essential to ensuring electric system reliability. 

The final guidelines’ approach to the interim emission 

performance rates is the result of the application of the 

measures constituting the BSER in a more gradual way, reflecting 

stakeholder comments and information about the appropriate 

period of time over which those measures can be deployed 

consistent with the BSER factors of cost and feasibility. In 

addition to facilitating reliable system operations, these 

changes provide states and utilities with the latitude to 

consider a broader range of options to achieve the required 

reductions while addressing concerns about ratepayer impacts and 

stranded assets. 

Revised BSER Determination 

Commenters urged the EPA to confine its BSER determination 

to actions that involve traditional generation. While some 

stakeholders recognized demand-side EE as being an integral part 

of the electricity system, with many of the charateristics of 

more traditional generating resources, other stakeholders did 

not. Though demand-side EE shares many of the characteristics of 

more traditional generation, the broad range of comments on this 

topic illustrate how much the role of demand-side resources is 
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changing and how the opportunities for generating companies to 

use demand-side resources varies more than the other building 

blocks (e.g., a broad range of types of generation owners 

including vertically integrated utilities, municipalities, 

cooperatives and independent power producers own or contract for 

renewable energy, but only a handful of independent power 

producers are currently providing demand-side resources like 

demand-side EE). The EPA has not included demand-side EE as part 

of the final BSER determination. Thus, neither the final 

guidelines’ BSER determination nor the emission performance 

rates for the two subcategories of affected EGUs take into 

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

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

element of their compliance strategies, as energy efficiency 

measures are in widespread use across the country and provide 

energy savings that reduce emissions, lower electric bills, and 

lead to positive investments and job creation. We agree, and the 

final guidelines provide ample latitude for states and utilities 

to rely on demand-side EE in meeting emission reduction 

requirements. 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 
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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. We also updated the underlying analysis with 

the most recent Energy Information Administration (EIA) 

projections that show lower growth in electricity demand between 

2020 and 2030 than previously projected. Due to these revised 

findings, we expect the final guidelines will be more conducive 

to compliance, consistent with an energy strategy that allows 

for the cleanest generation and greater reductions in 2030 than 

the proposal. 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. 

After consideration of 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 
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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. 

Uniform Emission Performance Rates 

Some stakeholders commented that the proposal’s approach of 

expressing the BSER in terms of state-specific goals deviated 

from the requirements of CAA section 111 and from previous new 

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

was that the proposal’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 stated that the EPA must establish the BSER 

specifically for affected sources, rather than by means of 

merely setting state-specific goals. The EPA carefully 

considered these comments and, in the final guidelines, 

maintains flexibilities for states through the state measures 

approach while also setting uniform rates for sources. 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 subcategories – fossil 

fuel-fired electric steam generating units and stationary 

Commented [A3]: It might be helpful to include blended rate 

and mass based plans as part of the flexibility maintained 
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combustion turbines – for the affected EGUs covered by the 

guidelines. States may comply with these guidelines by adopting 

these emission rates as emission standards for their sources. 

Each state also has the option of complying with these 

guidelines by adopting a plan that is projected to achieve 

equivalent emission reductions as determined by the state goal. 

We emphasize, therefore, that while the final guidelines now 

take a source-specific approach to setting CO2 emission 

performance rates, as a proposal, each state will have a goal 

tailored to its particular mix of sources, and the final 

guidelines retain the flexibility inherent in the proposal’s 

state-specific goals approach (and, as discussed in Section VIII 

of this preamble, enhanced in various ways). Thus, to maintain 

the proposal’s flexibility for states, for those states that 

choose not to adopt the emission performance rates as emission 

standards for their sources, the guidelines continue to define 

state planning and implementation obligations through state 

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. 

State Measures Approach
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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 a 

variation of the “portfolio” approachthat 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 standards” approach, and a “state measures” approach 

that requires the inclusion of backstop measures. To comply with 

these guidelines, states will either have to set emission 

standards equal to the performance rates or adopt plans that 

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, 

achieve 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. 
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Emission Trading Programs

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 EGUs. In 

addition, in response to concerns from states and power 

companies that the need for up-front interstate cooperation in 

developing multi-state plans could inhibit the development of 

interstate programs that could lower cost, the final rule 

provides additional options to allow individual EGUs to use 

creditable out-of-state reductions to achieve required CO2

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

The EPA is committed to working with states to provide support 

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

approaches. 

Extension of Plan Submittal Date 

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 

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. 

Provisions for Electric System Reliability 
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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. The final 

guidelines support electric system reliability in a number of 

ways, some inherent in the program’s design and some through 

specific requirements we have included. Most important, perhaps, 

are the change of the interim period from 2020 to 2022 and the 

adjustments to the interim period glide path. In addition, the 

final guidelines require states to 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 

the requirements imposed on an affected unit and the maintenance 

of reliability. The final rule also retains flexibilities 
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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. 

Community Considerations 

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. 

Resources and Outreach 

In their comments, many states identified the need for the 

EPA to maintain regular contact/forums with states throughout 
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the implementation process and to provide training and guidance, 

including guidance on RE and EE emission measurement and 

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

other stakeholders, including communities, with an understanding 

of the rule requirements, and to provide efficiencies where 

possible and reduce the cost and administrative burden, the EPA 

will continue outreach throughout the plan development and 

submittal process. Outreach will include opportunities for 

states to participate in briefings, teleconferences, and 

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 
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documents, tools, templates and other resources become 

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

Energy and other federal agencies, will continue to make these 

resources available via a dedicated website. 

3. Context for this rulemaking

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 and constitutes a major 

commitment by one of the world’s largest GHG emitters. GHG 

pollution threatens the American public by leading to damaging 

and long-lasting changes in our climate that can have a range of 

severe negative effects on human health and the environment. CO2

is the primary GHG pollutant, accounting for nearly threequarters of global GHG emissions5 and 82percent of U.S. GHG 

emissions.6 The May 2014 report of the National Climate 

Assessment7 concluded that climate change impacts are already 

 

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 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. 

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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manifesting themselves and imposing losses and costs. The report 

documents increases in extreme weather and climate events in 

recent decades, with resulting damage and disruption to human 

well-being, infrastructure, ecosystems, and agriculture, and 

projects continued increases in impacts across a wide range of 

communities, sectors, and ecosystems. New scientific assessments 

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

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 populations and some communities of color 

(more specifically, populations defined jointly by ethnic/racial 

characteristics and geographic location), are disproportionately 

affected by certain climate change related impacts — including 

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

which are associated with increased deaths, illnesses, and 

economic challenges. Studies also find that climate change poses 

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

indigenous peoples in the United States. 

b. The utility power sector. One of the strategies of the 
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President’s Climate Action Plan is to reduce CO2 emissions from 

power plants.8 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 

Memorandum9 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. 

 

8 The President’s Climate Action Plan, June 2013, calls for a 

wide range of activities, including . 

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

climateactionplan.pdf

9 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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The utility power sector is unlike any other industrial 

sector. In all other sectors, 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 other networked systems like trains and pipeline 

systems). That grid is physically interconnected and operated on 

an integrated basis across large regions. In this interconnected 

system, system operators must reliably balance supply and demand 

using available generation and demand-side resources, including 

energy efficiency, demand response and a wide range of low- and 

zero-emitting sources. These resources are managed to meet the 

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

this interconnected system is highly regulated and coordinated 

with electric generators who are required to respond to the 

system operator's dispatch instructions. Each step of the 

process from the electric generator to the end user is highly 

regulated by multiple entities working in coordination and 

considering overall system reliability. For example, in an ISO 

or RTO with a centralized, organized capacity market, electric 

Commented [A4]: Is this descriptive of how the grid is managed 

in non-ISO/RTO areas? 
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generators are paid to be available to run when needed, must bid 

into energy markets, must respond to dispatch instructions, and 

must have permission to schedule maintenance. The ISO/RTO 

dispatches resources in a way that maintains electric system 

reliability. 

The approach we take in the final guidelines is in tune with 

the interconnected and highly regulated nature of the utility 

power sector, the daily operation of affected EGUs within this 

framework, and the critical role of utilities in providing 

reliable, affordable electricity within this complex, regulated 

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. 

In this integrated system, numerous entities have both the 

capability and the responsibility to maintain a reliable 

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

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. 
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Critical to this function are dispatch tools, applied primarily 

by RTOs, ISOs, and balancing authorities, that operate such that 

actions taken or costs incurred at one source directly affect or 

cause actions to occur at other sources. Generation, outages, 

and transmission changes in one part of the synchronous grid can 

affect the entire interconnected grid.10 The interconnection is 

such that “[i]f a generator is lost in New York City, its effect 

is felt in Georgia, Florida, Minneapolis, St. Louis, and New 

Orleans.”11 The U.S. Supreme Court has explicitly recognized the 

interconnected nature of the electricity grid.12 

 

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

Systems, IEEE Press, at 159 (2d ed. 2010). 11 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 160 (2d ed. 2010). 12 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 
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The uniqueness of the utility power sector inevitably 

affects the way in which environmental regulations are designed. 

When the EPA promulgates environmental regulations that affect 

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

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

importance of the efficient and continuous, uninterrupted 

operation of the interconnected electricity system in which EGUs 

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

interconnected system provides – electricity services – and the 

critical role of this sector to the U.S. economy and to the 

fundamental well-being of all Americans. 

In the context of environmental regulation, Congress, the 

EPA and the states all have recognized 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 

 

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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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, which enabled pollution reduction 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 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 
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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 such as renewable 

generation. For example, many states have adopted renewable 

portfolio standards (RPS). In other cases, utilities have chosen 

to construct renewable generation, 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 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 
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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 

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 
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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 and also 

increase the momentum due to the imperative posed by climate 

change impacts. This final rule provides flexibility for states 

to build upon their progress, and the progress of cities and 

towns, in addressing GHGs, and minimizes additional requirements 

for existing programs where possible. It also allows states to 

pursue policies to reduce carbon pollution that: 1) continue to 

rely on a diverse set of energy resources; 2) ensure electric 

system reliability; 3) provide affordable electricity; 4) 

recognize investments that states and power companies are 

already making; and 5) tailor plans to meet their respective 

energy, environmental and economic needs and goals, and those of 

their local communities. Thus, the final guidelines will achieve 

meaningful CO2 emission reductions while maintaining the 

reliability and affordability of electricity in the U.S. 

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 

Commented [A5]: It might be helpful to reframe with language 

closely linked to the final BSER description. This reads very 

expansively. 
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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 that 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),13 states must establish, in their 

state plans, emission standards that reflect the degree of 

emission limitation achievable through the application of the 

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

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

health and environmental impacts and energy requirements, the 

Administrator determines has been adequately demonstrated 

 

13 See also 40 CFR 60.22(b)(5). 
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(BSER).14 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 sources in each of the two categories can 

achieve through the application of the BSER. States may comply 

by adopting these emission performance rates as their emission 

standards. States may use other mechanisms for achieving the 

BSER-level reductions, such as a more holistic energy sector 

approach like Colorado’s Clean Energy, Clean Jobs Plan, or use 

proven tools like emission markets as both states participating 

in the RGGI program and California have done. The EPA is 

finalizing guidelines that provide flexibility to take these 

types of approaches. For states that choose to use these types 

of alternative approaches, the EPA is also finalizing a single 

combined statewide emission rate limitation for each state and a 

 

14 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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statewide mass limitation for each state. States can either use 

these limits as a basis for their emission standards or use them 

as a basis for demonstrating that other emission standards they 

wish to use are equivalent to the BSER. 

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 emission standards 

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 
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the EPA determines constitute the BSER or to apply any one 

of those measures to the same extent that the EPA 

determines is achievable at reasonable cost on a national 

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

have the flexibility to select the measure or combination 

of measures it prefers in order to achieve the CO2 emission 

performance rates for its affected EGUs or meet the 

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

state could choose to achieve more reductions from one 

measure encompassed by the BSER and less from another, or 

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

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

as detailed in Section VIII of this preamble. Expressing 

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

can be met in aggregate, including through the adoption of 

CO2 emission reduction measures that are not identical to 

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

rather than exclusively through source-specific emission 

performance rates, is entirely permissible precisely 

because the approach mirrors the foundation of the BSER 

approach itself, namely the interconnected nature of the 

electricity system in which affected EGUs operate. 
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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 from the 

emission guidelines we proposed in June 2014, the proposed 

guidelines arethe 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 – indeed, 

provides more time - which is instrumental to ensuring both 

manageable costs and system reliability and to facilitating 

clean energy innovation. The final rule continues to express the 
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CO2 emission reduction requirements in terms of a state 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. The final guidelines also continue to provide an 

option where programs beyond those directly affecting rates can 

be used (i.e., measures). The final rule also continues to 

allow, but does not require, multi-state approaches. 

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 
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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) 

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 
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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 three main elements: 1) 

numerical source category-specific CO2 emission performance rates 

resulting from application of the BSER to the twosubcategories 

of affected EGUs, which can be adopted by states as emission 

standards, 2) tailored state-level CO2 goals that are translated 

from these emission performance rates based on each state’s 

fleet, and 3) guidelines for the development, submittal and 

implementation of state plans that implement those rates either 

directly or through measures that achieve the equivalent, in 

aggregate, of those rates as determined by the state goals.15 

In this final action, the EPA is setting emission 

performance rates for two subcategories of affected fossil 

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

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

fired EGUs, generate the state’s carbon intensity goal for 

 

15 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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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 if a state chooses 

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

guidelines do identify the methods which a state can or, in 

some cases, 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 implementing 

them by creating plans that are consistent with the EPA 

emission guidelines. The EPA recognizes that each state has 

differing policy considerations – including varying 

regional emission reduction opportunities and existing 

state programs and measures – and that the characteristics 

of the electricity system in each state (e.g., utility 

regulatory structure and generation mix) also differ. 

Therefore, as in the proposal, each state will have the 
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latitude to design a program to meet source-category 

specific emission performance rates or the equivalent 

statewide rate- or mass-based goal in a manner that 

reflects its particular circumstances and energy and 

environmental policy objectives. Each state can do so on 

its own, or a state can collaborate with other states 

and/or tribal governments on multi-state plans – or states 

can include in their plans the trading tools that EGUs can 

use to realize additional opportunities for cost savings 

while continuing to operate across the interstate system 

through which electricity is produced. A state would also 

have the option of adopting the model rules for either a 

rate- or a mass-based program that the EPA is proposing 

concurrent with this action, or of becoming subject to the 

EPA’s federal plan, also being proposed concurrent with 

this action.16 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 

 

16 The EPA’s proposed federal plan is being published 

concurrently with this final rule. 
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meet the emission guidelines, and the options they have in 

the timing of submittal of their plans. This final rule 

also gives states considerable flexibility with respect to 

the timeframes for plan development and implementation, as 

well as the choice of emission reduction measures. The 

final rule provides up to fifteen years for full 

implementation of all emission reduction measures, with 

incremental steps for planning and then for demonstration 

of CO2 reductions that will ensure that progress is being 

made in achieving CO2 emission reductions. States will be 

able to choose from a wide range of emission reduction 

measures, including measures that are not part of the BSER, 

as discussed in detail in Section VIII.G of this preamble. 

d. Determination of the BSER. In issuing this final 

rulemaking, the EPA is implementing statutory provisions 

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 emission standards to 
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achieve emission reductions consistent with the BSER. In 

following the provisions, the EPA is finalizing a BSER 

based on strategies currently being used by states and 

companies to reduce CO2 emissions from EGUs as the “best” 

approaches(e.g., on-site efficiency improvements, shifting to lower-emitting and zeroemitting generation).

In this final action, the agency has determined that the 

BSER comprises the first three of the four proposed building 

blocks, with certain refinements to the three building blocks. 

The three building blocks – on-site efficiency improvements, generation shifts to existing gas, 

and use of renewable energy – are all approaches that are available to all affected EGUs. In 

addition, emission trading is also available. 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 shifting generation to 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 zero-emitting generation provided by RE 

facilities. 

Formatted: Font: 8 pt

Formatted: Font: 8 pt
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The CAA, as interpreted by the courts, identifies several 

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

include technical feasibility, costs, size of emission 

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

implementation and further development of technology). In 

determining the BSER for this industrial sector, the EPA 

considered the reductions achievable through measures that 

reduce CO2 emissions from existing fossil fuel-fired EGUs either 

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

reducing the units’ CO2 emission total to the extent that 

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

EGUs to lower- or zero-emitting options. 

As the EPA has done in making BSER determinations in 

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

the types of strategies that states and owners and operators of 

EGUs are already employing to reduce the covered pollutant (in 

this case, CO2) from affected sources (in this case, fossil fuelfired EGUs).17 

 

17 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 
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To determine the BSER for reducing CO2 emissions at 

affected EGUs and to establish the emission guidelines that 

reflect the BSER, the EPA considered numerous measures that 

can and are being implemented to improve emission rates and 

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

EGUs. These measures encompass two basic approaches: 1) 

reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 

addressing affected EGUs’ mass emissions by varying their 

generation 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: 

 

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

destroying the organic content of the gas on the premises using 

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

practice already being used by some affected sources prior to 

promulgation of the rulemaking.
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1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

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

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from zeroemitting generating units for reduced generation from 

affected fossil fuel-fired generating units. 

The building blocks are described in detail in Section 

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

evaluated each of the building blocks individually against 

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

blocks independently merits consideration as part of the 

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

achievable by individual sources and by the source 

category, it will result in meaningful emission reductions 

at reasonable cost, and it satisfies the other BSER 

factors. (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 
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potential building block in the June 18, 2014 proposal, as 

a component of the BSER.) 

The EPA also evaluated combinations of the three building 

blocks against the BSER factors in making its determination. The 

EPA determined that the combination of all three building blocks 

is the BSER,. taking into account the fact that the widely 

demonstrated availability of the trading of emission rate 

credits or mass allowances can enable any given EGU to achieve 

its emission reduction obligations (i.e., if an EGU should 

choose not to meet its obligations simply by limiting its own 

operations, it could rely on the interconnected function of the 

electricity system to effectuate replacement generation from new 

clean generation or from shifting generation to 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. In reaching this determination, the EPA has taken 

into account the fact that the interconnected design and 

Deleted: ).

Commented [A6]: This language seemed quite helpful—could it 

be reinstated? 
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operation of the electricity system can enable any given 

affected EGU to achieve its emission reduction obligation by 

cross-investing in emission reductions at other affected EGUs, 

providing flexibility as to the electricity system locations 

where heat rate improvements, increases in generation from 

existing NGCC units, increases in renewable energy generation, 

and decreases in generation from higher-emitting affected EGUs 

take place. The EPA has also taken into account the opportunity 

for such cross-investments to be facilitated by emissions 

trading -- a mechanism that is suitable for this global 

pollutant, appropriate for and widely demonstrated in this 

highly transactional industry, and of interest to numerous 

states and utilities –- which would allow cross-investments to 

take the form of purchases of rate-based emission credits or 

mass-based emission allowances. 

For the final rule, in response to stakeholder comments and 

considerable data in the record, 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 

Commented [A7]: Would this result in credits for the investing 

source or a reduction in its generation, thus enabling it to meet its 

compliance rate? It would be helpful to have a fuller explanation of 

how these cross-investments secure compliance outside of a credit 

trading framework. 
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blocks. The agency also recognizes the important functional 

relationship between the period of time over which measures are 

deployed and the stringency of emission limitations those 

measures can achieve 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. 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. Also, as detailed in Section VIII of this 

preamble, the EPA believes that the features of the final rule 

avoid adverse impacts to electric system reliability. In 

summary, the EPA determined that the BSER for purposes of CAA 

section 111(d), as applied to existing fossil fuel-fired EGUs, 

is based on a combination of measures that reduce CO2 emissions 
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and CO2 emission rates and encompasses three building blocks,

together with facilitated by opportunities for cross-investment 

and emissions trading.18 

In determining the BSER, we considered the ranges of 

reductions that can be achieved at reasonable cost by 

application of each building block, considering both 

stringency and time, and we have calculated CO2 emission 

performance rates for the categories of fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. Rather than the maximum possible 

degree of application, we have finalized what we believe 

reflects a reasonable degree of application of each 

building block consistent with the BSER criteria. Relying 

on the three building blocks to characterize the 

combination of measures that reduce CO2 emissions and CO2

emission rates at affected EGUs as the basis for the BSER 

is consistent with strategies, actions and measures that 

companies and states are already undertaking to reduce GHG 

 

18 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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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 
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designed to meet. For fossil fuel-fired steam generating units, 

we are finalizing an emission performance rate of 1,290 lb/MWh 

of CO2. For stationary combustion turbines, we are finalizing an 

emission performance rate of 780 lb/MWh of CO2. 

To continue to provide the flexibility inherent in the 

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

rule, the EPA has translated the source category-specific 

CO2 emission performance rates into equivalent statewide 

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

in Section VII of this preamble. 

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 
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are achieved, in order to address key issues such as cost 

to consumers, electricity system reliability and the 

remaining useful life of existing generation assets. 

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

goals. 

The EPA recognizes that, with many measures, states can 

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

circumstances, such as those for which instrumental 

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

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

generating capacity, the full effects of implementation can take 

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

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 expressed by some 

stakeholders that required CO2 emission reductions could not be 

achieved as early as 2020 without compromising electric system 

reliability, affecting affordability, and requiring investments 
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in more carbon-intensive generation – and to reflect the period 

of time required through the process of state plan development 

and submission to the EPA, the EPA review and approval and state 

and EGU implementation of approved plans - the EPA is 

establishing an eight-year interim period over which to achieve 

the full required reductions to meet the CO2 performance rates, 

and this begins in 2022, more than six years from [INSERT THE 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], the date of this 

rulemaking. This eight-year interim period from 2022 through 

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

2028-2029, each associated with its own interim CO2 emission 

performance rates. These steps respond to many comments we 

received requesting a more graduated trajectory. A state may 

adopt emission standards for its sources that are identical to 

these interim emission performance rates. Alternatively, 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 state’s 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 
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provides for electricity system reliability, avoids the creation 

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

the parlance of numerous state and stakeholder discussions, 

states can determine their own respective emission reduction 

trajectories or “glide paths”.

We believe that this approach for achieving CO2

reductions over time responds both to the needs of an 

effectively implemented program and to the persuasive 

arguments presented by stakeholders regarding balancing the 

simultaneous need for both flexibility and certainty about 

what will constitute an approvable state plan. We likewise 

believe that this approach also represents a reasonable 

balance between two competing objectives grounded in CAA 

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

calculating emission reductions reflecting the BSER and a 

need to provide the states with flexibility in establishing 

and implementing the emission standards or measures that 

reflect those emission reductions. The importance of this 

balance is heightened by the fact that the operations of 

the electricity system itself rely on the flexibility made 

available and achieved through shifting generation between 

and among multiple interconnected EGUs, demand management 
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and demand-side energy efficiency. This approach recognizes 

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

consistent with a vibrant and growing economy and the ample 

supply of reliable, affordable electricity needed to 

support that economy. It further reflects the growing 

trend, as exemplified by many state and local clean energy 

policies and programs, to shift energy production away from 

carbon-intensive fuels to a modern, more sustainable system 

that puts greater reliance on renewable energy, energy 

efficiency and other low-carbon energy options. 

f. State plans.19 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 

 

19

 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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monitoring and periodic reporting of progress. As with the 

BSER determination, stakeholder comments have provided both 

data and recommendations to which these final guidelines 

are responsive. 

(1) Plan approaches. 

To comply with these emission guidelines, a state will have 

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

establishes for its sources individually, in aggregate, or in 

combination with other measures undertaken by the state, 

represent the equivalent of the source category-specific 

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

provided in section VII of this preamble and in a TSD.20 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 contingent backstop of federally 

 

20 The ...goal computation TSD. 
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enforceable emission standards for affected EGUs that fully meet 

the emission guidelines and that would be triggered if the plan 

failed to achieve the required emission reductions on schedule. 

A state would have the option of basing its backstop emission 

standards on the 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 

necessary. Beginning January 1, 2025, and then January 1, 2028, 

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

the state will be required to compare emission levels achieved 

by affected EGUs in the state with the emission levels projected 

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

the EPA by July 1 of those calendar years. 

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 
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provide the states with the ability to achieve the full 

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

reduction strategies, using state-specific or multi-state 

approaches that can be achieved on either a rate or mass 

basis. They also address several key policy considerations 

that states can be expected to contemplate in developing 

their plans. 

State plan approaches and plan guidelines are explained 

further in Section VIII of this preamble. 

(2) State plan components and approvability criteria. The 

EPA’s implementing regulations provide certain basic elements 

required for state plans submitted pursuant to CAA section 

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

certain additional elements that should be contained in state 

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

making several revisions to the components required in a state 

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 
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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 goal21

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

demonstrate that they are actively engaging all stakeholders 

including potentially affected communities as part of their 

public participation process. In the initial plan submittal and 

complete plan submittal, states will have to provide a summary 

 

21 A state that chooses to set emission standards that are 

identical to the emission performance rates for both the interim 

period and in 2030 and beyond need not identify interim state 

goals nor include a separate demonstration that its plan will 

achieve the state goals. 
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of how they are engaging with all stakeholders, including 

overburdened communities. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard will result in 

reductions that are quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure will result in reductions that are 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 

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

Because of the compelling need for actions to begin the steps 

necessary to reduce GHG emissions from EGUs, the EPA proposed 

that states submit their plans within 13 months of the date of 
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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. Commenters, especially states, 

have also provided further information about the steps needed to 

develop and put in place all of the components needed for a 

final state plan. The EPA agrees with these comments, which we 

believe support extending the start date of the compliance 

period from 2020 to 2022 and retaining the requirement that 

initial plans be submitted without additional delay, while also 

providing a full three years for submittal of final state plans. 

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 
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a final plan, then the state may submit an initial plan by 

August 31, 2016, that documents the reasons the state needs more 

time and includes commitments to concrete steps that will ensure 

that the state will submit a final plan by August 31, 2018. To 

be approvable, the EPA is finalizing that the initial plan 

submittal must address all components of a final plan submittal, 

including identifying which components are not complete. The 

initial plan must include specific components, including a 

justification for seeking an extension, a description of the 

plan approach, a commitment to maintain existing measures that 

limit CO2 emissions, progress to date in developing a final plan, 

a comprehensive roadmap of the path to completion including 

specific steps the state, sources or other entities will be 

implementing in order to meet the initial compliance 

requirements beginning in 2022, and demonstration of opportunity 

for public comment on the submittal and a summary of the state’s 

response to any significant public comment on the approvability 

of the initial plan, as described in Section VIII.E of this 

preamble. 

If the initial submittal includes those components and if 

the EPA does not notify the state that the initial submittal 

does not contain the required components, the extension of time 
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to submit a final plan will be deemed granted and a state will 

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

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

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

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

their jurisdictional boundaries may participate in emission 

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

to adjust CO2 emission rates for affected EGUs). 

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given the diverse 

approaches states may take to meet the CO2 emission 

performance rates or equivalent statewide goals in the 

emission guidelines, the EPA is extending the period for 

EPA review and approval or disapproval of plans from the 

four-month period provided in the EPA implementing 

regulations to a twelve-month period. This timeline will 

provide adequate time for the EPA to review plans and 

follow notice-and-comment rulemaking procedures that ensure 

that provide an opportunity for public comment. The EPA, 

especially through our regional offices, will be available 

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

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

slow down approval of state plans. 

(4) Timing for implementing the CO2 emission guidelines. 

 The EPA recognizes that the measures states and utilities 

have been and will be taking to reduce CO2 emissions from 

existing EGUs can take time to implement. 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 emission 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 emission performance rates, or must 

meet the equivalent statewide interim period goals, on average, 

that a state may establish over the 8-year period from 2022-

2029, which the state must reflect in its CAA section 111(d) 

plan. Affected EGUs must also achieve the final CO2 performance 

rates or the equivalent statewide goal by 2030 and maintain that 

level subsequently. This approach reflects adjustments to the 
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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. 

The EPA recognizes that successfully achieving reductions 

by 2022 will require actions that lead to some CO2 emission 

reductions prior to 2022. The final rule requires that the state 

plan submittal include a timeline with all of the programmatic 

milestone steps the state will take between the time of the 

state plan submittal and the year 2022 to ensure that the plan 

is effective as of 2022. States must submit a report to the EPA 

in 2021 that demonstrates that the state has met the 

programmatic milestone steps that the state indicated it would 

take during the period from the submittal of the final plan 

through the end of 2020, and that the state is on track to 

implement the approved state plan as of January 1, 2022. 

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 

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if anything, would necessarily take place before 2022, anticipating 

stay litigation 
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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 commenters expressed concerns that regulatory 

mechanisms that states put in place to reduce CO2 emissions could 

inadvertently create unwanted effects that could lead to 

increases in CO2 emissions from EGUs. In the final rule, we have 

put in place safeguards against this, including provisions for 

states to provide periodic demonstrations that, at the state 

level, CO2 emission reductions are being achieved. 

Further discussion of timing is presented in Section VIII.G 

of this preamble. 

(5) Community considerations. 

This rule will provide broad benefit to communities across 

the nation by reducing greenhouse gas emissions and will be 

particularly beneficial to populations that are particularly 

vulnerable to the impacts of climate change and air pollution. 

Moving the utility power sector toward cleaner generation and 

more energy efficiency is expected to reduce costs to ratepayers 

overall, which will benefit low-income ratepayers. 
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In this final rule, the EPA is taking steps to ensure that 

this rulemaking does not have any potential disproportionate, 

adverse health effects and environmental effects on overburdened 

communities. To provide information fundamental to ensuring that 

this rulemaking does not have disproportionate adverse impacts 

on overburdened communities, the EPA has conducted a proximity 

analysis for this rulemaking. Additionally, the EPA is 

encouraging states to conduct analyses of their own when 

developing their plans. The EPA is requiring states to 

demonstrate that they are actively engaging with a diverse range 

of stakeholders, including overburdened communities, as part of 

their public participation process. In their initial plan 

submittal, states will have to provide 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 

provide meaningful opportunities for engagement with the public, 

including overburdened communities, during the final plan 

development process, pursuant to the public participation 

requirements of the implementing regulations. This engagement 

could include topics such as potential localized impacts and how 

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the state will assess any impacts of their plan on overburdened 

communities, among others. 

The EPA is also encouraging states, in developing their 

plans, to use state models that help low-income populations 

access the benefits of EE, RE, and financial assistance programs 

and to also consider, and minimize, any adverse impacts that 

their plans could have on communities, including impacts on 

jobs. 

The EPA will also provide information resources for 

affected communities and states on existing federal, state, and 

local and other financial assistance programs available to 

communities. 

(6) 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. The input we received on this issue focused 

heavily on the extent of the reductions required at the 

beginning of the interim period, proposed as 2020. We are 

addressing these concerns in large part by moving the start date 

of the program from 2020 to 2022 and significantly adjusting the 

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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. These adjustments in the interim 

goals are supported by the information in the record concerning 

the time needed to develop and implement reductions under the 

BSER. In addition, the various forms of flexibility retained and 

enhanced in this final rule, including opportunities for trading 

within and between states, and other multi-state compliance 

approaches, will further support electric system reliability. In 

addition, numerous commenters urged us to include, as part of 

the plan development or approval process, input from review by 

energy regulatory agenciesIn the final rule, we are requiring 

that each state demonstrate in its final state plan submittal 

that it has considered reliability issues in developing its 

plan, which it can do, for example, by consulting with relevant 

ISOs/RTOs or other planning authorities. 

The final guidelines address electric system reliability in 

several additional ways. We recognize that issues may arise 

during the implementation of the guidelines that may warrant 
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adjustments to a state’s plan in order to maintain electric 

system reliability. The final guidelines make clear that states 

have the ability to propose amendments to approved plans in the 

event that unanticipated and significant reliability challenges 

arise. And, as a final element of reliability assurance, the 

rule also provides for a reliability safety valve for 

individual sources where there is a conflict between the 

requirements the state plan imposes on a specific affected EGU 

and the maintenance of electric system reliability due to an 

extraordinary, unanticipated, potentially catastrophic event. 

We anticipate that these situations will be rare because 

the states have the flexibility to craft requirements for their 

EGUs that will provide long averaging periods and/or compliance 

mechanisms, such as trading, that are unlikely to put an 

individual unit in this kind of situation. We, nevertheless, 

agree with many commenters that it is prudent to provide an 

electric system reliability safety valve as a precaution. In 

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

efforts to help ensure continued reliable electricity generation 

and transmission during the implementation of the final 

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

their joint understanding of how they will work together to 
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monitor implementation, share information, and to resolve any 

difficulties that may be encountered. 

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

provide states and affected EGUs with meaningful time and 

decision making latitude, we believe that the comprehensive 

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

system reliability will continue to operate effectively as 

affected EGUs reduce their CO2 emissions under this program. 

(7) Outreach and resources for stakeholders. To provide 

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

other interested stakeholders with understanding about the rule 

requirements, and to provide efficiencies where possible and 

reduce the cost and administrative burden, the EPA will continue 

to work with states, tribes, and stakeholders to provide 

information and address questions about the final rule. Outreach 

will include opportunities for states and tribes to participate 

in briefings, teleconferences, and meetings about the final 

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

entry point for states, tribes and territories to ask technical 

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

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

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

will also offer consultations with tribal 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 that 

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

are implementing the final rule. 

The EPA has worked with communities, states, tribes and 

relevant associations to develop an extensive training plan that 

will continue in the months after the Clean Power Plan is 

finalized. The EPA has assembled resources from a variety of 

sources to create a comprehensive training curriculum for those 

implementing the Clean Power Plan. Recorded presentations from 

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

communities, states, and others involved in composing and 

participating in the development of state plans. This curriculum 

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

The EPA also expects to issue guidance on specific topics. 

As guidance documents, tools, templates and other resources 

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

Department of Energy and other federal agencies, will continue 
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to make these resources available via a dedicated website.22 

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). 

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. 

 

22 www.epa.gov/cleanpowerplantoolbox. 
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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).23 The air pollution health co-

 

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

the monetary value of impacts associated with a marginal change 

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

changes in CO2 emissions expected from this rulemaking. The four 

SCC estimates are associated with different discount rates 

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

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

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

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

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

 

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

model average at 3 percent discount rate. 
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The annual compliance costs are estimated using the 

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

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 

Formatted Table
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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 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 
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PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

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

estimate includes monitoring, recordkeeping, and reporting costs 

and demand side energy efficiency program and participant costs. 

e The estimates of net benefits in this summary table are 

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

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

estimates based on additional discount rates. 

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)24 and cobenefits from reducing direct exposure to SO2, NOX, and 

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

 

24 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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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 

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-years25 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 

 

25 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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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 

of the preamble, we present a summary of the rule requirements 

and the legal basis for these. Section IV explains the EPA 

authority to regulate CO2 and EGUs, identifies affected EGUs, and 

describes the proposed treatment of source categories. Section V 

describes the agency’s determination of the BSER using three 

building blocks and our key considerations in making the 

determination. Section VI provides the 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. 
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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], 

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 
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rulemaking,26 followed by information on stakeholder outreach and 

consultations and the comments that the EPA received prior to 

issuing this final rulemaking. 

A. Climate Change Impacts from GHG Emissions 

According to the National Research Council, “Emissions 

of CO2 from the burning of fossil fuels have ushered in a 

new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere 

is long lived, it can effectively lock Earth and future 

generations into a range of impacts, some of which could 

become very severe. Therefore, emission reduction choices 

made today matter in determining impacts experienced not 

just over the next few decades, but in the coming centuries 

and millennia.”27 

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).28 In the 

 

26 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). 

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

28 “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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Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

levels unprecedented in human history—may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., 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 
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other areas of public health, such as the potential for 

increased deaths, injuries, infectious and waterborne diseases, 

and stress-related disorders. Children, the elderly, and the 

poor are among the most vulnerable to these climate-related 

health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding 

Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

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

country at serious risk of reduced water supplies, increased 

water pollution, and increased occurrence of extreme events such 

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

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

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

to inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand. 

Extreme weather from climate change threatens energy, 

transportation, and water resource infrastructure. Climate 
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change may also exacerbate ongoing environmental pressures in 

certain settlements, particularly in Alaskan indigenous 

communities, and is very likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

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

security issues for the U.S. 

3. New scientific assessments and observations 

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

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

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

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

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 

These assessments, from the Intergovernmental Panel on Climate 
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Change (IPCC), the U.S. Global Change Research Program (USGCRP), 

and the National Research Council (NRC), include: IPCC’s 2012 

Special Report on Managing the Risks of Extreme Events and 

Disasters to Advance Climate Change Adaptation (SREX) and the 

2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 

National Climate Assessment, Climate Change Impacts in the 

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A 

National Strategy to Meet the Challenges of a Changing Ocean

(Ocean Acidification), 2011 Report on Climate Stabilization 

Targets: Emissions, Concentrations, and Impacts over Decades to 

Millennia (Climate Stabilization Targets), 2011 National 

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

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

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

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

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

Implications for Security Analysis (Climate and Social Stress), 

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these recent assessments in 

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

2009 Endangerment Finding, which was to rely primarily upon the 
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major assessments by the USGCRP, the IPCC, and the NRC of the 

National Academies to provide the technical and scientific 

information to inform the Administrator’s judgment regarding the 

question of whether GHGs endanger public health and welfare. 

These assessments addressed the scientific issues that the EPA 

was required to examine, were comprehensive in their coverage of 

the GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. 

The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 

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

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

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

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 
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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 

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.”29 

 

29 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. 
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In addition, increasing temperatures and loss of Arctic sea ice 

increases the risk of drowning for those engaged in traditional 

hunting and fishing. 

 The NCA3 concludes that children’s unique physiology and 

developing bodies contribute to making them particularly 

vulnerable to climate change. Impacts on children are expected 

from heat waves, air pollution, infectious and waterborne 

illnesses, and mental health effects resulting from extreme 

weather events. The IPCC AR5 indicates that children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. The IPCC finds that additional health concerns may arise 

in low income households, especially those with children, if 

climate change reduces food availability and increases prices, 

leading to food insecurity within households. 

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events. 

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, Cambridge, p. 1581. 
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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.30 In fact, that assessment stated that 

“the magnitude and rate of the present greenhouse gas increase 

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

increases in radiative forcing of the global climate system in 

Earth history.”31 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 

 

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

1.

31 Id., p.138.
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rapid and potentially permanent—at least on a human timescale—

changes not anticipated by climate models tuned to modern 

conditions may occur.” The NRC Abrupt Impacts report analyzed 

the threat of species extinction as an example of an 

irreversible impact that is expected to be exacerbated by 

climate change. Species at most risk include those whose 

migration potential is limited, whether because they live on 

mountaintops or fragmented habitats with barriers to movement, 

or because climatic conditions are changing more rapidly than 

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

is not presently possible to place exact probabilities on the 

added contribution of climate change to extinction, they did 

find that there was substantial risk that impacts from climate 

change could, within a few decades, drop the populations in many 

species below sustainable levels thereby committing the species 

to extinction. 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. 
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Future temperature changes will depend on what emission 

path the world follows. In its high emission scenario, the IPCC 

AR5 projects that global temperatures by the end of the century 

will likely be 2.6 °C to 4.8 °C (4.7 to 8.6 °F) warmer than 

today. Temperatures on land and in northern latitudes will 

likely warm even faster than the global average. However, 

according to the NCA3, significant reductions in emissions would 

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 
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projects that heavy downpours are expected to increase in many 

regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 

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

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 

grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 out of 10 summers would be 

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

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 
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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,”32 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3°C 

will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

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.”33 Also, because of the inertia of the oceans, sea level 

 

32 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28. 33 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

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

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 

 

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

Program, p. 9. 
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which their traditions and cultural identities are tied.”34 The 

IPCC AR5 notes, “Climate-related hazards exacerbate other 

stressors, often with negative outcomes for livelihoods, 

especially for people living in poverty (high confidence). 

Climate-related hazards affect poor people’s lives directly 

through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”35 

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, 

 

34 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. 

35 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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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 

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

years.”36 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.”37 

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 

 

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

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5. 

37 Ibid. 
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affected societies or global systems to manage and that have 

global security implications serious enough to compel 

international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

addressing changing security needs in the Arctic as sea ice 

retreats. 

In addition to future impacts, the NCA3 emphasizes that 

climate change driven by human emissions of GHGs is already 

happening now and it is happening in the 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 
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degrees F since 1895, with most of that increase occurring since 

1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 

2010. Contributing to this rise was the warming of the oceans 

and melting of land ice. It is likely that 275 gigatons per year 

of ice melted from land glaciers (not including ice sheets) 

since 1993, and that the rate of loss of ice from the Greenland 

and Antarctic ice sheets increased substantially in recent 

years, to 215 gigatons per year and 147 gigatons per year 

respectively since 2002. For context, 360 gigatons of ice melt 

is sufficient to cause global sea levels to rise 1 mm. Annual 

mean Arctic sea ice has been declining at 3.5 to 4.1 percent per 

decade, and Northern Hemisphere snow cover extent has decreased 

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

decade for June. Permafrost temperatures have increased in most 

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

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. 
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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.38 The average concentration in 2013, 

the last full year before this rule was proposed, was 396 parts 

per million. The average concentration in 2014 was 399 parts per 

million. And the monthly concentration in April of 2014 was 401 

parts per million, the first time a monthly average has exceeded 

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

1958, and for at least the past 800,000 years.39 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 1993.40 And 2014 was the 

 

38ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx

t

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

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

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238. 
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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 2002.41 The 

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

record. 

These assessments and observed changes make it clear that 

reducing emissions of GHGs across the globe is necessary in 

order to avoid the worst impacts of climate change, and 

underscore the urgency of reducing emissions now. The NRC 

Committee on America’s Climate Choices listed a number of 

reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”42 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 

 

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

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

Press. 
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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, 

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 
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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 

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 
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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. 

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 
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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 

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 
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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 

conditions. Low lying coastal areas, including the cities of 

Seattle and Olympia, will experience heightened risks of sea 
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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 

threaten humans, ecosystems, and infrastructure. Precipitation 
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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 of commercially and culturally important marine 

fish. 

In the Southwest, temperatures are now about 2 °F higher 

than the past century, and are already the warmest that region 

has experienced in at least 600 years. The NCA notes that there 
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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 
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California. Increased drought, higher temperatures, and bark 

beetle outbreaks are likely to contribute to continued increases 

in wildfires. The highly urbanized population of the Southwest 

is vulnerable to heat waves and water supply disruptions, which 

can be exacerbated in cases where high use of air conditioning 

triggers energy system failures. 

The rate of warming in the Midwest has markedly accelerated 

over the past few decades. Temperatures rose by more than 1.5 °F 

from 1900 to 2010, but between 1980 and 2010 the rate of warming 

was three times faster than from 1900 through 2010. 

Precipitation generally increased over the last century, with 

much of the increase driven by intensification of the heaviest 

rainfalls. Several types of extreme weather events in the 

Midwest (e.g., heat waves and flooding) have already increased 

in frequency and/or intensity due to climate change.

In the future, if emissions continue increasing, the 

Midwest is expected to experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. Though projections of 

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 long-
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term decreases in agricultural productivity, changes in the 

composition of the region’s forests, increased public health 

threats from heat waves and degraded air and water quality, 

negative impacts on transportation and other infrastructure 

associated with extreme rainfall events and flooding, and risks 

to the Great Lakes including shifts in invasive species, 

increases in harmful algal blooms, and declining beach health. 

High temperatures (more than 100 °F in the Southern Plains 

and more than 95 °F in the Northern Plains) are projected to 

occur much more frequently by mid-century. Increases in extreme 

heat will increase heat stress for residents, energy demand for 

air conditioning, and water losses. North Dakota’s increase in 

annual temperatures over the past 130 years is the fastest in 

the contiguous U.S., mainly driven by warming winters. Specific 

vulnerabilities highlighted by the NCA include increased demand 

for water and energy, changes to crop growth cycles and 

agricultural practices, and negative impacts on local plant and 

animal species from habitat fragmentation, wildfires, and 

changes in the timing of flowering or pest patterns. Communities 

that are already the most vulnerable to weather and climate 

extremes will be stressed even further by more frequent extreme 
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events occurring within an already highly variable climate 

system. 

In Hawaii, other Pacific islands, and the Caribbean, rising 

air and ocean temperatures, shifting rainfall patterns, changing 

frequencies and intensities of storms and drought, decreasing 

baseflow in streams, rising sea levels, and changing ocean 

chemistry will affect ecosystems on land and in the oceans, as 

well as local communities, livelihoods, and cultures. Low 

islands are particularly at risk. 

Rising sea levels, coupled with high water levels caused by 

tropical and extra-tropical storms, will incrementally increase 

coastal flooding and erosion, damaging coastal ecosystems, 

infrastructure, and agriculture, and negatively affecting 

tourism. Ocean temperatures in the Pacific region exhibit strong 

year-to-year and decadal fluctuations, but since the 1950s, they 

have exhibited a warming trend, with temperatures from the 

surface to a depth of 660 feet rising by as much as 3.6°F. As a 

result of current sea level rise, the coastline of Puerto Rico 

around Rincón is being eroded at a rate of 3.3 feet per year. 

Freshwater supplies are already constrained and will become more 

limited on many islands. Saltwater intrusion associated with sea 

level rise will reduce the quantity and quality of freshwater in 
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coastal aquifers, especially on low islands. In areas where 

precipitation does not increase, freshwater supplies will be 

adversely affected as air temperature rises. 

Warmer oceans are leading to increased coral bleaching 

events and disease outbreaks in coral reefs, as well as changed 

distribution patterns of tuna fisheries. Ocean acidification 

will reduce coral growth and health. Warming and acidification, 

combined with existing stresses, will strongly affect coral reef 

fish communities. For Hawaii and the Pacific islands, future sea 

surface temperatures are projected to increase 2.3°F by 2055 and 

4.7°F by 2090 under a scenario that assumes continued increases 

in emissions. Ocean acidification is also taking place in the 

region, which adds to ecosystem stress from increasing 

temperatures. Ocean acidity has increased by about 30% 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 
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Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2, and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. 

This section describes the amounts of these emissions and places 

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

Gas Emissions and Sinks43 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program44 (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 

 

43 “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

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

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html
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the information in Table 2 below, which presents total U.S. 

anthropogenic emissions and sinks45 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013. 

Table 2. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))46

SECTOR 1990 2005 2013 

Energy47 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

 

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

forests or underground or deep sea reservoirs of carbon dioxide.

46 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 

47 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel 

combustion and fugitive fuel emissions. 

Formatted Table
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Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.3 percent of total 

2013 GHG emissions.48 In 2013, fossil fuel combustion by the 

utility power sector –- entities that burn fossil fuel and whose 

primary business is the generation of electricity –- accounted 

for 38.3 percent of all energy-related CO2 emissions.49 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)50

 

48 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

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

Environmental Protection Agency, April 15, 2015. 

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

. 

49 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 

50 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

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

present comprehensive total U.S. greenhouse gas emissions and 

comply with commitments under the UNFCCC, the EPA collects 

detailed GHG emissions data from the largest emitting facilities 

in the U.S. through its Greenhouse Gas Reporting Program 

(GHGRP). Data collected by the GHGRP from large stationary 

sources in the industrial sector show that the utility power 

sector emits far greater CO2 emissions than any other industrial 

sector. Table 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)51

 

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

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

 - from natural gas 175.3 318.8 441.9

 - from petroleum 97.5 97.9 22.4

Industrial Sector 2013 Formatted Table
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C. The Utility Power Sector 

1. A brief history 

The modern American electricity system is one of the 

greatest engineering achievements of the past 100 years. Since 

the invention of the incandescent light bulb in the 1870s,52

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.53 During the early 1900s, smaller systems 

consolidated, allowing generation resources to be shared over 

 

52 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

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

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

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

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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larger areas. Interconnecting systems have reduced generation 

investment costs and improved reliability.54 Local and state 

governments initially regulated these growing electricity 

systems with federal regulation coming later in response to 

public concerns about rising electricity costs.55 

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.56 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 

 

54 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. 

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

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

56 The FPC became an independent Commission in 1930. United 

States Government Manual 1945: First Edition, at 486, available 

at http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html. 
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allow state regulation to directly burden interstate commerce.57

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.58 The Supreme Court 

found that Rhode Island’s regulation was impermissible because 

it imposed a "direct burden upon interstate commerce."59 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."60

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

 

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

5 (2002) (citation omitted).

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

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

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

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

60 16 U.S.C. § 824(b)(1). 
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rates for jurisdictional services are just, reasonable, and not 

unduly discriminatory or preferential.61 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.62 In 1938, Congress passed 

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

transmission or sale of natural gas in interstate commerce.63 The 

NGA also gave the FPC the jurisdiction to “grant certificates 

allowing construction and operation of facilities used in 

interstate gas transmission and authorizing the provision of 

services.”64 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, 

 

61 16 U.S.C. § 824d. 

62 16 U.S.C. § 824e. 

63 Energy Information Administration, Natural Gas Act of 1938, 

available at 

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

ajorleg/ngact1938.html. 

64 Energy Information Administration, Natural Gas Act of 1938, 

available at 

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

ajorleg/ngact1938.html. 
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transmission, and distribution - were common.65 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.66 

However, these larger plants were extremely capital intensive 

for any one company to fund.67 Some neighboring utilities solved 

this issue by agreeing to share electricity reserves when 

needed.68 These utilities began building larger transmission 

lines to deliver power in times when large generators 

experienced outages.69 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 

 

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

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

66 Federal Energy Regulatory Commission, Energy Primer: A 

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

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

67 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.

68 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.

69 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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electric generation units to a system operator.70 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.71 However, 

the ability of electric utilities to operate as natural 

monopolies came with consumer protection safeguards.72 “In 

exchange for a franchised, monopoly service area, utilities 

accept an obligation to serve – meaning there must be adequate 

supply to meet customers’ needs regardless of the cost.”73 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 

 

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

Business, Enerdynamics, at 94 (2012). 71 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). 

72 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. 

73 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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decades.74 In the early 1990s, some states began to consider 

allowing competition to enter retail electric service.75 Federal 

and state efforts to allow competition in the electric utility 

industry have resulted in independent power producers (IPPs)76

producing approximately 37 percent of net generation in 2013.77

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 

 

74 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). 

75 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). 

76 These entities are also referred to as merchant generators. 

77 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. 
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States.78 These utilities include both investor-owned utilities79

and consumer-owned utilities.80 

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.81 These larger transmission 

 

78 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

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

79 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. 

80 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. 

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

the Competitive Era, Public Utility Reports, Inc., at 5, 34 

(1997). “The extent of the power system’s short-run physical 

interdependence is remarkable, if not entirely unique. No other 

large, multi-stage industry is required to keep every single 

producer in a region – whether or not owned by the same company 

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

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

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

from peak use in other systems. They also recognized that 

equipment failures occurred at different times in various 

systems. Analyses showed significant economic benefits from 

interconnecting systems to provide mutual assistance; the 

investment required for generating capacity could be reduced and 

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

development of local, then regional, and subsequently three 
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lines are able to access generation that is located more 

remotely, with transmission lines crossing many miles, including 

state borders.82 Closer to end users, electricity is transformed 

into a lower voltage that is transported across localized 

transmission lines to homes and businesses.83 Localized 

transmission lines make up the distribution system. These three 

components of the electricity system - generation, transmission, 

and distribution - are closely related and must work in 

coordination to deliver electricity from the point of generation 

to the point of consumption. This interconnectedness is a 

fundamental aspect of the nation’s electricity system, requiring 

 

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). 82 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.

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

the Competitive Era, Public Utility Reports, Inc., at 5 (1997). 
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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.84 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.85 These 

three synchronous systems each act like a single machine.86

 

84 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. 

85 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

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

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

Systems, IEEE Press, at 159 (2d ed. 2010). In an amicus brief to 

the Supreme Court, a group of electrical engineers, economists, 

and physicists specializing in electricity explained, “Energy is 

transmitted, not electrons. Energy transmission is accomplished 

through the propagation of an electromagnetic wave. The 
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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, 

 

electrons merely oscillate in place, but the energy – the 

electromagnetic wave – moves at the speed of light. The 

energized electrons making the lightbulb in a house glow are not 

the same electrons that were induced to oscillate in the 

generator back at the power plant. . . . Energy flowing onto a 

power network or grid energizes the entire grid, and consumers 

then draw undifferentiated energy from that grid. A networked 

grid flexes, and electric current flows, in conformity with 

physical laws, and those laws do not notice, let alone conform 

to, political boundaries. . . . The path taken by electric 

energy is the path of least resistance . . . or, more 

accurately, the paths of least resistance. . . . If a generator 

on the grid increases its output, the current flowing from the 

generator on all paths on the grid increases. These increases 

affect the energy flowing into each point in the network, which 

in turn leads to compensating and corresponding changes in the 

energy flows out of each point.” Brief Amicus Curiae of 

Electrical Engineers, Energy Economists and Physicists in 

Support of Respondents at 2, 8-9, 11, New York v. FERC, 535 U.S. 

1 (2001) (No. 00-568).
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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 resources87, 

such as energy efficiency88 and demand response.89 Generation, 

outages, and transmission changes in one part of the synchronous 

grid can affect the entire interconnected grid.90 The 

 

87 “Measures using demand-side resources comprise actions taken 

on the customer’s side of the meter to change the amount and/or 

timing of electricity use in ways that will provide benefits to 

the electricity supply system.” David Crossley, Regulatory 

Assistance Project (RAP), Effective Mechanisms to Increase the 

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

www.raponline.org. 

88 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. 

89 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. 

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

Systems, IEEE Press, at 159 (2d ed. 2010).
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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.”91 The U.S. Supreme Court has 

similarly recognized the interconnected nature of the 

electricity grid.92 

Today, federal, state, and local entities regulate 

electricity providers.93 Overlaid on the physical electricity 

network is a regulatory network that has developed over the last 

 

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

Systems, IEEE Press, at 160 (2d ed. 2010). 92 Federal Power Comm’n v. Florida Power & Light Co., 404 U.S. 

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

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

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

instantly is caused to produce some quantity of additional 

electric energy which serves to maintain the balance in the 

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

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

(stating that “any electricity that enters the grid immediately 

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

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

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

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

electricity from Southern California Edison to the City of 

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

Power Commission jurisdiction because some of the electricity 

that Southern California Edison marketed came from out of state. 

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

follow the flow of electric energy, an engineering and 

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

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

Power Commission, 324 U.S. 515, 529 (1945) (emphasis omitted)). 93 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010).
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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.”94 

This unique regulatory network results in an electricity grid 

that is both physically interconnected and connected through a 

network of regulation on the local, state, and federal levels. 

This regulation seeks to reconcile the fact that electricity is 

a public good with the fact that facilities providing that 

electricity are privately owned.95 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.96 “The role of the 

regulator now includes support for the development of open and 

fair wholesale electric markets, ensuring equal access to the 

 

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

Systems, IEEE Press, at 213 (2d ed. 2010). 95 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 213 (2d ed. 2010). 96 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010).
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transmission system and more hands-on oversight and control of 

the planning and operating rules for the industry.”97 

2. Electric system dispatch 

System operators typically dispatch the electric system 

through a process known as Security Constrained Economic 

Dispatch.98 Security Constrained Economic Dispatch has two 

components – economic generation of generation facilities and 

ensuring that the electric system remains reliable.99 Electricity 

demand varies across geography and time in response to numerous 

conditions, such that electric generators are constantly 

responding to changes in the most reliable and cost-effective 

manner possible. The cost of operating electric generation 

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

efficiency. 

 

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

Systems, IEEE Press, at 214 (2d ed. 2010). 98 Economic Dispatch: Concepts, Practices and Issues, FERC Staff 

Presentation to the Joint Board for the Study of Economic 

Dispatch, Palm Springs, California (Nov. 13, 2005). 

99 Federal Energy Regulatory Commission, Security Constrained 

Economic Dispatch: Definitions, Practices, Issues and 

Recommendations: A Report to Congress (July 31, 2006). The 

Energy Policy Act of 2005 defined economic dispatch as “the 

operation of generation facilities to produce energy at the 

lowest cost to reliably serve consumers, recognizing any 

operational limits of generation and transmission facilities.” 

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

(2005), section 1234(b). 
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 The decision to dispatch any particular electric generator 

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

generating electricity to meet the last increment of electric 

demand. Fuel is one common variable cost – especially for 

fossil-fueled generators. Coal plants will often have 

considerable variable costs associated with running pollution 

controls.100 Renewables, hydroelectric, and nuclear have little 

to no variable costs. If electricity demand decreases or 

additional generation becomes available on the system, this 

impacts how the system operator will dispatch the system. EGUs 

using technologies with relatively low variable costs, such as 

nuclear units and RE, are for economic reasons generally 

operated at their maximum output whenever they are available. 

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

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

to be displaced. 

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

balancing authorities who determine dispatch based upon the 

lowest marginal cost. These utilities sometimes arrange to buy 

 

100 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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and sell electricity with other balancing authorities. RTOs and 

ISOs coordinate, control, and monitor electricity transmission 

systems to ensure cost-effective and reliable delivery of power, 

and they are independent from market participants. 

3. Reliability considerations 

The reliability of the electric system has long been a 

focus of the electric industry and regulators. Industry 

developed a voluntary organization in the early 1960s that 

assisted with bulk power system coordination in the U.S. and 

Canada.101 In 1965, the northeastern U.S. and southeastern 

Ontario, Canada experienced the largest power blackout to date, 

impacting 30 million people.102 In response to the 1965 blackout 

and a Federal Power Commission recommendation,103 industry 

developed the National Electric Reliability Council (NERC) and 

 

101 North American Electric Reliability Corporation, History of 

NERC, at 1 (2013), available at

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

102 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. 

103 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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nine reliability councils. The organization later became known 

as the North American Electric Reliability Council to recognize 

Canada’s participation.104 The North American Electric 

Reliability Council became the North American Electric 

Reliability Corporation in 2007.105 

In August 2003, North America experienced its worst 

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

and Ontario, Canada.106 This blackout was massive in scale 

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

megawatts of electric load.107 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 

 

104 North American Electric Reliability Corporation, History of 

NERC, at 2 (2013), available at

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

105 North American Electric Reliability Corporation, History of 

NERC, at 4 (2013), available at

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

106 North American Electric Reliability Corporation, History of 

NERC, at 3 (2013), available at

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

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

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

Causes and Recommendations, at 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. 
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the task force’s major recommendations was that the U.S. 

Congress should pass legislation making electric reliability 

standards mandatory and enforceable.108

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.109 In 2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as the ERO.110 “NERC develops 

and enforces Reliability Standards; monitors the Bulk-Power 

System; assesses adequacy annually via a 10-year forecast and 

 

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

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

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

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 109 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)). 

110 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). 
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winter and summer forecasts; audits owners, operators and users 

for preparedness; and educates and trains industry personnel.”111

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

up into eight reliability regional entities.112 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).113 Regional entity 

members come from all segments of the electric industry.114 NERC 

delegates authority, with FERC approval, to these regional 

 

111 North American Electric Reliability Corporation, Frequently 

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

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

112 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. 

113 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. 

114 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. 
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entities to enforce reliability standards, both national and 

regional reliability standards, and engage in other standardsrelated duties delegated to them by NERC.115 NERC ensures that 

there is a consistency of application of delegated functions 

with appropriate regional flexibility.116 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/RTOs117, and other planning 

 

115 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

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

For example, a regional entity may propose reliability 

standards, including regional variances or regional reliability 

standards required to maintain and enhance electric service 

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

Amended and Restated Delegation Agreement Between North American 

Reliability Corporation and Midwest Reliability Organization, 

Bylaws of the Midwest Reliability Organization, Inc., Section 

2.2 (2012), available at

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

eements%20DL/MRO_RDA_Effective_20130612.pdf. 

116 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

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

117 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, 
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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.118 In recent years, the 

 

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.”). 

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

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at
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nation has seen a sizeable increase in renewable generation such 

as wind and solar, as well as a shift from coal to natural 

gas.119 In 2013, fossil fuels supplied 67 percent of U.S. 

electricity,120 but the amount of renewable generation capacity 

continued to grow.121 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.122 Renewable electricity generation, 

 

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

visited May 26, 2015). 

119 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). 

120 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). 

121 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. 

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

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at
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including from large hydro-electric projects, grew from 8 

percent to 13 percent over that time period.123 Between 2000 and 

2013, approximately 90 percent of new power generation capacity 

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

energy facilities.124 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 2020.125 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. 

 

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

visited May 26, 2015).

123 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). 

124 Energy Information Administration, Electricity: Form EIA-860 

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

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

125 EIA, Annual Energy Outlook for 2015 with Projections to 2040, 

Final Release, available at

http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEO 

numbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.
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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 45.126 In its 2013 Report Card 

for America’s Infrastructure, the American Society for Civil 

Engineers noted that “America relies on an aging electrical grid 

and pipeline distribution systems, some of which originated in 

the 1880s.”127 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.”128 However, innovative 

 

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

the NEEDS inventory (a “snapshot” of the sector in 2016), and 

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

See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx. 127 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

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

128 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 
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technologies have increasingly entered the electric energy 

space, helping to provide new answers to how to meet the 

electricity needs of the nation. These new technologies can 

enable the nation to answer not just questions as to how to 

reliably meet electricity demand, but also how to meet 

electricity demand reliably and cost-effectively with the lowest 

possible emissions and the greatest efficiency. 

Natural gas has a long history of meeting electricity 

demand in the U.S., with a rapidly growing role as domestic 

supplies of natural gas have dramatically increased. Natural gas 

net generation increased by approximately 32 percent between 

2005 and 2014.129 In 2014, natural gas accounted for 

approximately 27 percent of net generation.130 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 2040.131 

 

129 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). 

130 Id. 131 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 
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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 

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).132 QFs were either cogeneration 

facilities133 or small generation resources that use renewables 

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

 

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. 

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

Systems, IEEE Press, at 220-221 (2d ed. 2010). 133 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). 
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as their primary fuels.134 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.135 

Use of RE continues to grow rapidly in the U.S. In 2013, 

electricity generated from renewable technologies, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity, up from 9 percent in 2005.136 In 2013, U.S. nonhydro RE capacity for the total electric power industry exceeded 

80,000 MW, reflecting a fivefold increase in just 15 years.137 In 

 

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

Systems, IEEE Press, at 220-221 (2d ed. 2010). 135 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). 

136 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2014) and Energy Information 

Administration, Monthly Energy Review, May 2015, Table 7.2b, 

available at

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

137 Non-hydro RE capacity for the total electric power industry 

was more than 16,000 megawatts (MW) in 1998. Energy Information 

Administration, 1990-2013 Existing Nameplate and Net Summer 

Capacity by Energy Source Producer Type and State (EIA-860), 

available at http://www.eia.gov/electricity/data/state/. 
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particular, there has been substantial growth in the wind and 

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

wind generation has tripled and solar generation has grown 

twenty-fold.138 

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

billion per year by 2030.139 RE growth is further encouraged by 

the significant amount of existing natural resources that can 

support RE production in the United States.140 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.141 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.142

 

138 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b, available at

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

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

Finance (Nov. 16, 2011), available at 

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

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

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

141 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. 

142 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2015), available at
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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.143 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 

states144 have “enacted long-term (3+ years), binding energy 

savings targets, or energy efficiency resource standards 

 

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last 

visited May 27, 2015).

143 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. 

144 American Council for an Energy-Efficient Economy, State 

Energy Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE 

did not include Indiana (EERS eliminated), Delaware (EERS 

pending), Florida (programs funded at levels far below what is 

necessary to meet targets), Utah, or Virginia (voluntary 

standards) in its calculation. 
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(EERS).”145 Funding for energy efficiency programs has grown 

rapidly in recent years, with budgets for electric efficiency 

programs totaling $5.9 billion in 2012.146 

 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. Clean Air Act Regulations for Power Plants 

In this section, we provide a general description of major 

CAA regulations for power plants. We refer to these in later 

sections of this preamble. 

1. Title IV Acid Rain Program 

The EPA’s Acid Rain Program, established in 1990 under 

Title IV of the CAA, addresses the presence of acidic compounds 

and their precursors (i.e., SO2 and NOx), in the atmosphere by 

 

145 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. 

146 American Council for an Energy-Efficient Economy, The 2013 

State Energy Efficiency Scorecard, at 17 (Nov. 2013), available 

at

http://aceee.org/sites/default/files/publications/researchreport

s/e13k.pdf. 
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targeting “the principal sources” of these pollutants through an 

SO2 cap-and-trade program for fossil-fuel fired power plants and 

through a technology based NOx emission limit for certain utility 

boilers. Altogether, Title IV was designed to achieve reductions 

of ten million tons of annual SO2 emissions, and, in combination 

with other provisions of the CAA, two million tons of annual NOx

emissions.147 

 The SO2 cap-and-trade program was implemented in two phases. 

The first phase, beginning in 1995, targeted one-hundred and ten 

named power plants, including specific generator units at each 

plant, requiring the plants to reduce their cumulative emissions 

to a specific level.148 Under certain conditions, the owner or 

operator of a named power plant could reassign an affected 

unit’s reduction requirement to another unit and/or request an 

extension of two years for meeting the requirement.149 Congress 

also established an energy conservation and renewable energy 

reserve from which up to 300,000 allowances could be allocated 

for qualified energy conservation measures or qualified 

renewable energy.150 

 

147 42 U.S.C. § 7651(b). 148 42 U.S.C. § 7651c (Table A). 149 42 U.S.C. § 7651c(b) and (d). 150 42 U.S.C. § 7651c(f) and (g). 
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The second phase, beginning in 2000, expanded coverage to 

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

million tons.151 Generally, allowances were allocated at a rate 

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

by 2000.152 However, bonus allowances could be awarded to certain 

units. 

Title IV also required the EPA to hold or sponsor annual 

auctions and sales of allowances for a small portion of the 

total allowances allocated each year. This ensured that some 

allowances would be directly available for new sources, 

including independent power production facilities.153 

The provisions of the EPA’s Acid Rain Program are 

implemented through permits issued under the EPA’s Title V 

Operating Permit Program.154 In accordance with Title IV, 

moreover, each Title V permit application must include a 

compliance plan for the affected source that details how that 

source expects to meet the requirements of Title IV.155 

 

151 U.S. Dept. of Energy, Energy Information Administration, “The 

Effects of Title IV of the Clean Air Act Amendments of 1990 on 

Electric Utilities: An Update,” p. vii. (March 1997). 

152 See 42 U.S.C. § 7651d. 153 42 U.S.C. § 7651o. 154 42 U.S.C. § 7651g. 155 Such plans may simply state that the owner or operator 

expects to hold sufficient allowances or, in the case of 
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2. Transport rulemakings 

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

Provision,” requires state implementation plans (SIPs) to 

prohibit emissions that “contribute significantly to 

nonattainment . . . or interfere with maintenance” of the NAAQS 

in any other state.156 If the EPA finds that a state has failed 

to submit an approvable SIP, the EPA must issue a federal 

implementation plan (FIP) to prohibit those emissions “at any 

time” within the next two years.157

In three major rulemakings—the NOx SIP Call,158 the Clean 

Air Interstate Rule (CAIR),159 and the Cross State Air Pollution 

Rule (CSAPR)160—the EPA has attempted delineate the scope of the 

Good Neighbor Provision. These rulemakings have several features 

in common. Although the Good Neighbor Provision does not speak 

specifically about EGUs, in all three rulemakings, the EPA set 

state emission “budgets” for upwind states based in part on 

 

alternative compliance methods, must provide a “comprehensive 

description of the schedule and means by which the unit will 

rely on one or more alternative methods of compliance in the 

manner and time authorized under [Title IV].” 42 U.S.C. § 

7651g(b). 

156 42 U.S.C. § 7410(a)(2)(D)(i)(I). 157 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 

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

158 63 FR 57356 (Oct. 27, 1998). 159 70 FR 25162 (May 12, 2005). 160 76 FR 48208 (Aug. 8, 2011). 
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emissions reductions achievable by EGUs through application of 

cost-effective controls. Each rule also adopted a phased 

approach to reducing emissions with both interim and final 

goals. 

a. NOx SIP Call. In 1998, the EPA promulgated the NOx SIP Call, 

which required 23 upwind states to reduce emissions of NOx that 

would impact downwind areas with ozone problems. The EPA 

determined emission reduction requirements based on reductions 

achievable through “highly cost-effective” controls—i.e., 

controls that would cost on average no more than $2,000 per ton 

of emissions reduced.161 The EPA determined that a uniform 

emission rate on large EGUs coupled with a cap-and-trade program 

was one such set of highly cost-effective controls.162 

Accordingly, the EPA established an interstate cap-and-trade 

program—the NOx Budget Trading Program—as a mechanism for states 

to reduce emissions from EGUs and other sources in a highly 

cost-effective manner. The D.C. Circuit upheld the NOx SIP Call 

in most significant respects, including its use of costs to 

apportion emission reduction responsibilities.163 

 

161 63 FR at 57377–78. 162 63 FR at 57377–78. In addition to EGUs, the NOx SIP Call also 

set budgets based on highly cost-effective emission reductions 

from certain other large sources. Id. 163 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). 
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b. Clean Air Interstate Rule (CAIR). In 2005, the EPA 

promulgated CAIR, which required 28 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

on “controls that are known to be highly cost effective for 

EGUs.”164 The EPA established cap-and-trade programs for sources 

of NOx and SO2 in states that chose to participate in the trading 

programs via their SIPs and for states ultimately subject to a 

FIP.165 As relevant here, the D.C. Circuit remanded CAIR in North 

Carolina v. EPA due to in part the structure of its interstate 

trading provisions and the way in which EPA applied the costeffective standard, but kept the rule in place while the EPA 

developed an acceptable substitute.166

c. Cross-state Air Pollution Rule (CSAPR). In 2011, the EPA 

promulgated CSAPR, which required 27 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

 

164 70 FR at 25163. 165 70 FR at 25273–75; 71 FR 25328 (April 28, 2006). 166 531 F.3d 896, 917–22 (D.C. Cir. 2008), modified on rehearing 

550 F.3d 1176, 1178 (D.C. Cir. 2008). 
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in part on the reductions achievable at certain cost thresholds 

by EGUs in each state, with certain provisions developed to 

account for the need to ensure reliability of the electric 

generating system.167 In the same action establishing these 

emission reduction requirements, the EPA promulgated FIPs that 

subjected states to trading programs developed to achieve the 

necessary reductions within each state.168 The U.S. Supreme Court 

upheld the EPA’s use of cost to set emission reduction 

requirements, as well as its authority to issue the FIPs.169 

3. Clean Air Mercury Rule 

On March 15, 2005, the EPA issued a rule to control mercury 

(Hg) emissions from new and existing fossil fuel-fired power 

plants under CAA section 111(b) and (d). The rule, known as the 

Clean Air Mercury Rule (CAMR), established, in relevant part, a 

nationwide cap-and-trade program under CAA section 111(d), which 

was designed to complement the cap-and-trade program for SO2 and 

NOx emissions under the Clean Air Interstate Rule (CAIR), 

 

167 76 FR at 48270. The EPA adopted this approach in part to 

comport with the D.C. Circuit’s opinion in North Carolina v. EPA 

remanding CAIR. Id. at 48270–71. 168 76 FR at 48209–16. 169 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 

(2014).
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discussed above.170 Though CAMR was later vacated by the D.C. 

Circuit on account of the EPA’s flawed CAA section 112 delisting 

rule, the court declined to reach the merits of the EPA’s 

interpretation of CAA section 111(d).171 Accordingly, CAMR 

continues to be an informative model for a cap-and-trade program 

under CAA section 111(d). 

The cap-and-trade program in CAMR was designed to take 

effect in two phases: in 2010, the cap was set at 38 tons per 

year, and in 2018, the cap would be lowered to 15 tons per year. 

The Phase I cap was set at a level reflecting the co-benefits of 

CAIR as determined through economic and environmental 

modeling.172 For the more stringent Phase II cap, the EPA 

projected that sources would “install SCR [selective catalytic 

reduction] to meet their SO2 and NOx requirements and take 

additional steps to address the remaining Hg reduction 

requirements under CAA section 111, including adding Hg-specific 

control technologies (model applies ACI [activated carbon 

 

170 See 70 F.R. 28606 (May 18, 2005). 171 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). 172 70 F.R. 28606, at 28617. The EPA’s projections under CAIR 

showed a significant number of affected sources would install 

scrubbers for SO2 and selective catalytic reduction for NOx on 

coal-fired power plants, which had the co-benefit of capturing 

mercury emissions. Id. at 28619.
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injection]), additional scrubbers and SCR, dispatch changes, and 

coal switching.”173 

To accompany the nationwide emissions cap, the EPA also 

assigned a statewide emissions budget for mercury. Pursuant to 

CAA section 111(d), states would be required to submit plans to 

the EPA “detailing the controls that will be implemented to meet 

its specified budget for reductions from coal-fired Utility 

Units.”174 Of course, states were “not required to adopt and 

implement” the emission trading program, “but they [were] 

required to be in compliance with their statewide Hg emission 

budget.”175 

4. Mercury Air Toxics Rule 

On February 16, 2012, the EPA issued the MATS rule (77 FR 

9304) to reduce emissions of toxic air pollutants from new and 

existing coal- and oil-fired EGUs. The MATS rule will reduce 

emissions of heavy metals, including mercury, arsenic, chromium, 

and nickel; and acid gases, including hydrochloric acid and 

hydrofluoric acid. These toxic air pollutants, also known as 

hazardous air pollutants or air toxics, are known to cause, or 

 

173 70 F.R. 28606, at 28619. 174 70 F.R. 28606, at 28621. 175 70 F.R. 28606, at 28621. That said, states could “require 

reductions beyond those required by the [s]tate budget.” Id. at 

28621. 
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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 
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administrative order that includes a compliance schedule of up 

to an additional year, if it is needed to ensure electricity 

reliability. 

5. Regional Haze Rule 

Under CAA section 169A, Congress “declare[d] as a national 

goal the prevention of any future, and the remedying of any 

existing, impairment of visibility” in national parks and 

wilderness areas that results from anthropogenic emissions.176 To 

achieve this goal, Congress directed the EPA to promulgate 

regulations directing states to submit SIPs that “contain such 

emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress toward meeting the 

national goal . . . .”177 One such measure that Congress deemed 

necessary to make reasonable progress was a requirement that 

certain older stationary sources that cause or contribute to 

visibility impairment “procure, install, and operate, as 

expeditiously as practicable . . . the best available retrofit 

technology,” more commonly referred to as BART.178 When 

determining BART for large fossil-fuel fired utility power 

 

176 42 U.S.C. § 7491(a)(1). 177 42 U.S.C. § 7491(b)(2). 178 42 U.S.C. § 7491(b)(2)(A). 
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plants, Congress required states to adhere to guidelines to be 

promulgated by the EPA.179 As with other SIP-based programs, the 

EPA is required to issue a FIP within two years if a state fails 

to submit a regional haze SIP or if the EPA disapproves such SIP 

in whole or in part.180

 In 1999, the EPA promulgated the Regional Haze Rule to 

satisfy Congress’ mandate that EPA promulgate regulations 

directing states to address visibility impairment.181 Among other 

things, the Regional Haze Rule allows states to satisfy the 

Act’s BART requirement either by adopting source-specific 

emission limitations or by adopting alternatives, such as 

emissions-trading programs, that achieve greater reasonable 

progress than would source-specific BART.182 The Ninth Circuit 

and D.C. Circuit have both upheld the EPA’s interpretation that 

CAA section 169A(b)(2) allows for BART alternatives in lieu of 

source-specific BART.183 In 2005, the EPA promulgated BART 

 

179 42 U.S.C. § 7491(b)(2). 180 42 U.S.C. §§ 7410(c); 7491(b)(2)(A). 181 64 Fed. Reg. 35,714 (July 1, 1999) (codified at 40 C.F.R. §§ 

51.308-309). 

182 40 C.F.R. § 51.308(e)(1) & (2). 183 See Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 (D.C. 

Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 

2005); Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 

1993). 
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Guidelines to assist states in determining which sources are 

subject to BART and what emission limitations to impose at those 

sources.184

 The Regional Haze Rule set a goal of achieving natural 

visibility conditions by 2064 and requires states to revise 

their regional haze SIPs every ten years.185 The first planning 

period, which ends in 2018, focused heavily on the BART 

requirement. States (or the EPA in the case of FIPs) made 

numerous source-specific BART determinations, and developed 

several BART alternatives, for utility power plants. For the 

next planning period, states will need to determine whether 

additional controls are necessary at these plants (and others 

that were not subject to BART) in order to make reasonable 

progress towards the national visibility goal.186

E. Early Evidence of Climatic Change in the Context of the CAA 

Amendments187 

 

184 70 Fed. Reg. 39,104 (July 6, 2005) (codified at 40 C.F.R. pt. 

51, app. Y). 

185 See 40 C.F.R. §§ 51.308(d)(1)(i)(B), (f). 186 See 42 U.S.C. § 7491(b)(2); 40 C.F.R. § 51.308(d)(3). 187 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 or was presented 

with evidence on climate change. 
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 As early as 1970, Congress learned that ongoing pollution, 

including from manmade carbon dioxide, could “threaten 

irreversible atmospheric and climatic changes.”188 Likewise, 

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.”189 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.”190 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 

 

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

Legis. Hist. at 349.

189 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.”). 

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

the Council on Environmental Quality,” p. 93-104 (Aug. 1970) 
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that reaches the earth.”191 Administrator Johnson explained that 

the Nixon Administration was “concerned ... that neither of 

these things happen” and that they were “watching carefully the 

kind of prognosis, the kind of calculations that the scientists 

make to look at the continuous balance between heat and cooling 

of the total earth’s atmosphere.”192 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.”193

Scientific reports on climatic change continued to gain 

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

Congress was considering the 1977 CAA Amendments. However, it 

was reported that science remained inconclusive as to the 

 

191 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. 

192 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. 

193 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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specific warming or cooling trends.194 In deference to that 

uncertainty, Congress ordered, as part of the 1977 CAA 

Amendments, the National Oceanic and Atmospheric Administration 

to research and monitor the stratosphere “for the purpose of 

early detection of changes in the stratosphere and climatic 

effects of such changes.”195 

By 1990 (if not by 1979), scientific uncertainty appeared 

to yield to the predominant view that global warming “was likely 

to dominate on time scales that would be significant to human 

societies.”196 Nevertheless, some reports continued to present 

 

194 For instance, while scientists, such as Stephen Schneider of 

the National Center for Atmospheric Research, testified that 

“manmade pollutants will affect the climate,” they believed that 

we would “see a general cooling of the Earth’s atmosphere.” Rep. 

Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA 

Legis. Hist. at 6477. Additionally, the Department of 

Transportation’s climatic impact assessment program and the 

Climatic Impact Committee of the National Research Council, 

National Academies of Science and Engineering both reported that 

“warming or cooling” could occur. Id. at 6476. See also Sen. 

Bumpers, Sen. Debates on S. 3219 (August 3, 1976), 1977 CAA 

Legis. Hist. at 5368 (inserting “Summary of Statements Received 

[in the Subcommittee on the Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of Chronic 

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

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”). 

195 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728. 196 Peterson, Thomas C., William M. Connolley, and John Fleck, 

“The Myth of the 1970s Global Cooling Scientific Consensus,” 

Bulletin of the American Meteorological Society, p. 1326 
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contrary views; thus, Congress perceived 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.”197 Accordingly, in the 1990 CAA 

Amendments, Congress specifically required the EPA to collect 

data on carbon dioxide emissions –- the most significant of the 

greenhouse gases -- from all sources subject to the newly 

enacted operating permit program under Title V.198Congress 

explained that the CO2 data collection requirement “helps fill 

this information gap” and would “give us a head start if and 

when we need to take steps to reduce our carbon dioxide 

emissions.”199Although Congress did not require the EPA to take 

immediate action to address climate change, Congress did 

identify certain tools that were particularly helpful in 

addressing climate change in the utility power sector. For 

instance, the Senate report discussing Title IV noted that 

 

(September 2008), available at 

http://journals.ametsoc.org/doi/pdf/10.1175/2008BAMS2370.1. 

197 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612. 

198 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 199 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612-13. 
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“[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.’”200

Similarly, “renewables not only significantly curtail sulfur 

dioxide emissions, but they emit little or no nitrogen oxides 

and carbon dioxide”.201 Both of these measures had also been 

identified as effective and available technologies and 

strategies for reducing SO2 to address acid rain. 

F. 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)202 is the international 

treaty under which countries (called “Parties”) cooperatively 

consider what can be done to limit anthropogenic climate 

change203 and adapt to climate change impacts. Currently, there 

 

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

Legis. Hist. at 8662. 

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

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

202 http://unfccc.int/2860.php 203 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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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 2025.204

 As Parties to both the UNFCCC and the Kyoto Protocol205, the 

European Union (EU) and member countries have taken aggressive 

action to reduce GHG emissions.206 EU initiatives to reduce 

greenhouse gas emissions include the EU Emissions Trading 

System, legislation to increase the adoption of renewable energy 

 

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 

204 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

205 http://unfccc.int/kyoto_protocol/items/2830.php 206 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm 

Formatted: Font: Times New Roman, Complex Script Font:

10 pt
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sources, strengthened energy efficiency targets, vehicle 

emission standards, and support for the development of CCS 

technology for use by the power sector and other industrial 

sources. In 2009, the EU announced its “20-20-20 targets,” 

including a 20% 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. 
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Brazil has reduced its net CO2 emissions more than any other 

country through a historic effort to slow forest loss. The 

deforestation rate in Brazil in 2014 was roughly 75% below the 

average for 1996 to 2005.207   

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.

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.”208 The Air Quality Act—which expanded 

federal air pollution control efforts after the enactment of the 

Clean Air Act of 1963—prioritized the adoption of ambient air 

standards but failed to target stationary sources of air 

pollution. As a result, “[c]ities up and down the east coast 

were living under clouds of smoke and daily air pollution 

 

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

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

Legis. Hist. at 224. 
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alerts.”209 In fact, “[o]ver 200 million tons of contaminants ... 

spilled into the air” each year.210 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”211 

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”.212 Under these provisions, 

 

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

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

210 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. 

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

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

212 “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 

Stat. 1676, 1678 (Dec. 31, 1970). The “adverse effect” criterion 

was later amended to refer to pollutants “which may reasonably 

be anticipated to endanger public health or welfare”. See 42 

U.S.C. § 7408(a)(1)(A). Similar language is also used under the 

current CAA section 111. See 42 U.S.C. § 7411(b)(1)(A). 
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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.213

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.”214 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 

 

213 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680. 214 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684. 
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to protect the public health”.215 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.216

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 112.217 That said, states, including Texas and New 

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

moving rapidly enough.218 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.”219

 

215 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 216 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 217 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 218 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 219 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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At bottom, CAA section 111 rests on the definition of a 

standard of performance under CAA section 111(a)(1), which reads 

nearly the same now as it did when it was first adopted in the 

1970 CAA Amendments. In 1970, Congress defined standard of 

performance—a term which had not previously appeared in the CAA—

as 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction) 

the Administrator determines has been adequately 

demonstrated.220

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

definition.221 As presently defined, the term applies to the 

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

and (d).222 

 

220 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 221 “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). 

222 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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The level of control reflected in the definition is 

generally referred to as the “best system of emission 

reduction,” or the BSER. The BSER, however, is not further 

defined, and only appeared after conference between the House 

and Senate in late 1970, and was neither discussed in the 

conference report nor openly debated in either chamber. 

Nevertheless, the originating bills from both houses shed light 

on its construction. 

The BSER grew out of proposed language in two bills, which, 

for the first time, targeted air pollution from stationary 

sources. The House bill sought to establish national emission 

standards to “prevent and control ... emissions [of nonhazardous pollutants] to the fullest extent compatible with the 

available technology and economic feasibility”.223 The House also 

proposed to prohibit the construction or operation of new 

sources of “extremely hazardous” pollutants.224 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 

 

223 H.R. 17255, 91st Cong. § 5 (1970). 224 H.R. 17255, 91st Cong. § 5 (1970). 
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available control technology, processes, operating methods, or 

other alternatives.”225 The Senate also would have authorized 

“national emission standards” for hazardous air pollution and 

other “selected air pollution agents.”226

After conference, CAA section 111 emerged as one of the 

CAA’s three programs for regulating stationary sources. In 

defining the newly formed “standards of performance,” Congress 

appeared to merge the various “means of preventing and 

controlling air pollution” under the Senate bill with the 

consideration of costs that was central to the House bill into 

the BSER. At the time, however, this definition only applied to 

new sources under CAA section 111(b). 

To regulate existing sources, Congress collapsed section 

114 of the Senate bill into CAA section 111(d).227 Section 114 of 

the Senate bill established emission standards for “selected air 

 

225 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). 

226 S. 4358, 91st Cong. § 6 (1970). 227 The House bill did not provide for the direct regulation of 

existing sources. 
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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 112.228 

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.”229 

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 112.230 That said, under the 

newly enacted “ambient air quality and emission standards” 

sections, Congress directed the EPA to provide states with 

 

228 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970). 229 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). 

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

1706. 
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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.”231 Similarly, 

the Administrator would “issue information on pollution control 

techniques for air pollutants” in conjunction with establishing 

emission standards under CAA section 112. However, analogous 

text is absent from CAA section 111(d). 

After the enactment of the 1970 CAA Amendments, the EPA 

proposed standards of performance for an “initial list of five 

stationary source categories which contribute significantly to 

air pollution” in August 1971.232 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.233 

 

231 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679. 232 “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). 

233 36 F.R. at 15704-706; and “Standards of Performance for New 

Stationary Sources,” 36 F.R. 24876, 24879 (Dec. 23, 1971). 
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Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).234 These regulations were 

finalized in November 1975, and provided for the publication of 

emission guidelines.235 The first emissions guidelines were 

proposed in May 1976 and finalized in March 1977.236

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.237 Most 

 

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

F.R. 36102 (Oct. 7, 1974). 

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

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

236 See “Phosphate Fertilizer Plants; Draft Guideline Document; 

Availability,” 41 F.R. 19585(May 12, 1976); and “Phosphate 

Fertilizer Plants; Final Guideline Document Availability,” 42 

F.R. 12022 (Mar. 1, 1977) 

237 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 
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notably, an increase in coal use as a result of the oil crisis 

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

“even more urgent.”238 Thus, to curb the projected surge in air 

emissions, Congress enacted several new provisions to the CAA. 

These new provisions include the prevention of significant 

deterioration (PSD) program, visibility protections, and 

requirements for nonattainment areas.239 

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 

 

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). 

238 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. 

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

127-129, 91 Stat. 685 (Aug. 7, 1977). 
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schedule for establishing standards of performance for 

categories of major stationary sources that had not yet been 

listed.240

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.’”241 For fossil-fuel 

fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.242 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.”243

 

240 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697. 241 H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 

separately defined “technological system of continuous emission 

reduction” as “(A) a technological process for production or 

operation by any source which is inherently low-polluting or 

nonpolluting, or (B) technological system for continuous 

reduction of the pollution generated by a source before such 

pollution is emitted into the ambient air, including 

precombustion cleaning or treatment of fuels.” “Clean Air Act 

Amendments of 1977,” § 109, 91 Stat. at 700; see also 42 U.S.C. 

§ 7411(a)(7). 

242 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700. 243 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 F.R. 33580, 33581-82 (June 

11, 1979). 
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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)”.244 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.”245 Additionally, Congress clarified that states could 

consider “the remaining useful life” of a source when applying a 

standard of performance to a particular existing source.246 

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.”247 Indeed, in 1988, 

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

enough and much remains to be done.’”248 This time, with the 1990 

CAA Amendments, Congress substantially overhauled the CAA. In 

 

244 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 245 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

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

246 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). 

247 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 248 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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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 

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 1977.249 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.250

Lastly, Congress instructed the EPA to revise its new source 

performance standards for SO2 emissions from fossil fuel-fired 

 

249 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. 

250 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631. 
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power plants but required that the revised emission rate be no 

less stringent than before.251

H. 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.”252 The EPA has listed more than 60 

stationary source categories under this provision.253 Once the 

EPA lists a source category, the EPA must, under CAA section 

111(b)(1)(B), establish “standards of performance” for emissions 

of air pollutants from new sources in the source categories.254

These standards are known as new source performance standards 

(NSPS), and they are national requirements that apply directly 

to the sources subject to them. 

 

251 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631. 252 CAA §111(b)(1)(A). 253 See 40 CFR 60 subparts Cb – OOOO. 254 CAA §111(b)(1)(B), 111(a)(1). 
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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.” 

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 
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EPA for approval, and the EPA must approve the state plan if it 

is “satisfactory.”255 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.256 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 

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 

 

255 CAA section 111(d)(2)(A). 256 CAA section 111(d)(2)(A). 
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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 country257 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 

 

257 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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avoid any doubt that the guidelines apply to U.S. territories 

with affected EGUs and to any Indian tribe that has been 

approved by the EPA as eligible to develop and implement a plan. 

In these final emission guidelines, the term “state” 

encompasses the 50 states and the District of Columbia, U.S. 

territories, and any Indian tribe that has been approved by the 

EPA pursuant to 40 CFR 49.9 as to develop and implement a CAA 

section 111(d) plan. 

The EPA issued regulations implementing CAA section 111(d) 

in 1975,258 and has revised them in the years since.259 (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.260 The implementing regulations also establish 

 

258 “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

259 The most recent amendment was in 77 Fed. Reg. 9304 (Feb. 16, 

2012). 

260 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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timetables for state and EPA action: states must submit state 

plans within 9 months of the EPA’s issuance of the guidelines,261

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

months of the due date for those plans,262 although the EPA has 

authority to extend those deadlines.263 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)).264 In addition, the agency has 

 

261 40 CFR 60.23(a)(1). 262 40 CFR 60.27(b). 263 See 40 CFR 60.27(a). 264 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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regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.265 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 

 

265 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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system by lowering the carbon intensity of power generation, 

while offering continued reliability and cost-effectiveness. 

These opportunities exist in the utility power sector in ways 

that were not relevant or available for other industries for 

which the EPA has established CAA section 111(d) emission 

guidelines.266

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. 

I. 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 

 

266 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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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 ratebased 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 
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trajectories created by the interim goal for 2020 to 2029, 2) 

certain aspects of the building block methodology, and 3) the 

way state-specific CO2 goals are calculated. 

In a separate action, the EPA published a notice regarding 

potential methods for determining the mass that is equivalent to 

an emission rate-based CO2 goal (79 FR 67406; November 13, 2014). 

With the notice, the EPA also made available, in the docket for 

this rulemaking, a technical support document (TSD) that 

provided two examples of how a state, U.S. territory or tribe 

could translate a rate-based CO2 goal to total metric tons of CO2

(a mass-based equivalent). 

J. Stakeholder Outreach and Consultations 

Following the direction in the Presidential Memorandum to 

the Administrator (June 25, 2013),267 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, 

 

267 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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non-governmental organizations, other federal agencies, other 

experts, community groups and members of the public. The EPA 

participated in more than 300 meetings before the rule was 

proposed and more than 300 after the proposal. 

Throughout the rulemaking process, the agency has 

encouraged, organized, and participated in hundreds of meetings 

about CAA section 111(d) and reducing carbon pollution from 

existing power plants. The agency’s outreach prior to proposal, 

as well as during the public comment period, was designed to 

solicit policy ideas,268 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,269

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 

 

268 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. 

269 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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under CAA section 111(d). The meetings were attended by the EPA 

Regional Administrators, other senior managers and staff who 

have been instrumental in the development of the rule and will 

play key roles in developing and implementing it. 

This outreach process has produced a wealth of information 

which has informed this rule significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialogue with states and stakeholders will continue 

after the rule is finalized. The EPA recognizes the importance 

of working with all stakeholders, and in particular with the 

states, to ensure a clear and common understanding of the role 

the states will play in addressing carbon pollution from power 

plants. We firmly believe that our outreach has resulted in a 

more workable rule that will achieve the statutory goals and has 

enhanced the likelihood of timely and successful achievement of 

the carbon reduction goals, given the critical importance and 

urgency of the concrete action. 

The EPA has given stakeholder comments careful 

consideration and, as a result, this final rule includes 

features that are responsive to many stakeholder concerns. 

1. Public hearings 
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More than 2,700 people attended the public hearings 

sessions held in Atlanta, Denver, Pittsburgh, and Washington, 

DC. More than 1,300 people spoke at the public hearings. 

Additionally, about 100 people attended the public hearing held 

in Phoenix, Arizona, on the November 4, 2014 supplemental 

proposal. Speakers at the public hearings included Members of 

Congress, other public officials, industry representatives, 

faith-based organizations, unions, environmental groups, 

community groups, students, public health groups, energy groups, 

academia and concerned citizens. 

Participants shared a range of perspectives. Many were 

concerned with the impacts of climate change on their health and 

on future generations, others were worried about the impact of 

regulations on the economy. Their support for the agency’s 

efforts varied. 

2. State officials 

Since fall 2013, the agency has provided multiple 

opportunities for the states to inform this rulemaking. 

Administrator McCarthy has engaged with governors from states 

with a variety of interests in the rulemaking. Other senior 

agency officials have engaged with every branch and major agency 

of state government - including state legislators, attorneys 
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general, state energy, environment, and utility officials, and 

governors' staff. 

On several occasions, state environmental commissioners met 

with senior agency officials to provide comments on the Clean 

Power Plan. The EPA organized, encouraged and attended meetings 

with states to discuss multi-state planning efforts. States have 

come together with several collaborative groups to discuss ways 

to work together to make the Clean Power Plan more affordable. 

The EPA has participated in and supported the states in these 

discussions. Because of the interconnectedness of the power 

sector, and the fact that electricity generated at power plants 

crosses state lines; states, utilities and ratepayers may 

benefit from states working together to implement the 

requirements of this rulemaking. The meetings provided state 

leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 

directors, opportunities to engage with the EPA officials. In 

addition, the states submitted public comments from several 

agencies within each state. The wealth of comments and input 

from states was important in developing the final rulemaking. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 
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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 

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 
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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 

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. 
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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 

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 
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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 

 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 
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the federally recognized tribes to ensure that they had the 

opportunity to have meaningful and timely input into this rule. 

Section III (“Stakeholder Outreach and Conclusions”) of the June 

18, 2014 proposal documents the EPA’s extensive outreach efforts 

to tribal officials prior to that proposal, including an 

informational webinar, outreach meeting, teleconferences with 

tribal officials and the National Tribal Air Association (NTAA), 

and letters offering consultation. Additional outreach to tribal 

officials conducted by the EPA prior to the November 4, 2014 

supplemental proposal is discussed in Section II.D (“Additional 

Outreach and Consultation”) of the supplemental proposal. The 

additional outreach for the supplemental proposal included 

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 
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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 

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 
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meeting with representatives from the Guam Environmental 

Protection Agency (GEPA) and the Guam Power Authority and, on 

February 18, 2015, the EPA met again with representatives from 

GEPA. 

5. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in many one-on-one and 

national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the rule 

is on the utility power sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the utility power sector. The agency has 

also met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

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 
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Agency officials participated in many meetings with 

utilities and their associations to discuss all aspects of the 

proposed guidelines. We have met with all types of companies 

that produce electricity, including private utilities or 

investor owned utilities. Public utilities and cooperative 

utilities were also part of in-depth conversations about CAA 

section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 

7. Electricity grid operators 

The EPA had a number of conversations with the 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 
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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 

policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. Many members of 

faith communities attended the four public hearings. 
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 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through 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 

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 
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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 

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 
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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 

the American Federation of Labor-Congress of Industrial 

Organizations (AFL-CIO) at the AFL-CIO headquarters. 
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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 

deploying and reliably integrating increased RE generation. 
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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 
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A. Summary of Rule Requirements 

The EPA is establishing emission guidelines for states to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction ... adequately demonstrated” 

(BSER) and include source category-specific CO2 emission 

performance rates, state-specific goals, requirements for state 

plan components, and requirements for the process and timing for 

state plan submittal and compliance. 

Under CAA section 111(d), the states must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” that, taking into account the cost 

of achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 

The EPA has determined that the BSER is the combination of 

emission rate improvements and limitations on overall emissions 

at affected EGUs that can be accomplished through any 

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 
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performance rates into equivalent statewide rate-based and massbased 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” 
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approach. With an emission standards approach, a state will 

apply all requirements for achieving the subcategory-specific CO2

emission performance rates or the state-specific CO2 emission 

goal to affected EGUs in the form of federally enforceable 

emission standards. With a state measures approach, a state plan 

would be comprised, at least in part, of measures implemented by 

the state that are not included as federally enforceable 

components of the plan, along with a backstop of federally 

enforceable emission standards for affected EGUs that would 

apply in the event the plan does not achieve its anticipated 

level of CO2 emission performance. 

The EPA is requiring states to make their initial plan 

submittals 13 months from the signature date of the rule and to 

make their final plan submittals no later than 3 years from the 

signature date of the rule. 

The EPA is 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 
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preamble. Affected EGUs must achieve the final emission 

performance rates or equivalent statewide goals by 2030 and 

maintain that level thereafter. 

The EPA is further establishing, as part of the guidelines, 

timetables for states to submit their plans. Each state must use 

the established electronic submittal system to provide the EPA 

its complete plan submittal by August 31, 2016. However, if a 

state needs additional time to provide the EPA with a complete 

plan submittal, the state must provide an initial plan submittal 

by August 31, 2016, that documents the reasons that more time is 

needed to provide a complete plan submittal and includes 

commitments to take concrete steps that will ensure that the 

state will submit a complete plan by August 31, 2018. 

For the final emission guidelines, the EPA is revising 

the list of components required in a 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:
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• 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 

• 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 
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complete plan development process pursuant to the public 

participation requirements of the implementing regulations. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard 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 
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tribe that has one or more affected EGUs in its area of Indian 

country,270 the tribe has the opportunity, but not the 

obligation, to establish a CAA section 111(d) plan for its area 

of Indian country. If a tribe with one or more affected EGUs 

located in its area of Indian country does not submit a plan or 

does not receive EPA approval of a submitted plan, the EPA has 

the responsibility to establish a CAA section 111(d) plan for 

that area if it determines that such a plan is necessary or 

appropriate. 

 During and following implementation of its 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 

 

270 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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matter, the EPA reasonably interprets the provisions identifying 

which air pollutants are covered under CAA section 111(d) to 

authorize the EPA to regulate CO2 from fossil fuel-fired EGUs. In 

addition, the EPA recognizes that CAA section 111(d) applies to 

sources that, if they were new sources, would be covered under a 

CAA section 111(b) rule. Concurrently with this rule, the EPA is 

finalizing a CAA section 111(b) rulemaking establishing 

standards of performance for CO2 emissions from new fossil 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;271 accordingly, in this rulemaking, the EPA is determining 

the BSER. 

 

271 The EPA is not re-opening that interpretation in this 

rulemaking. 
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The EPA is finalizing the BSER for fossil fuel-fired EGUs 

based on building blocks 1, 2, and 3. Building block 1 includes 

operational improvements and equipment upgrades that the coalfired steam-generating EGUs in the state may undertake to 

improve their heat rate. It qualifies as part of the BSER 

because it improves the carbon intensity of the affected EGUs in 

generating electricity through actions the affected sources may 

undertake that are adequately demonstrated and whose cost is 

“reasonable.” Building blocks 2 and 3 include increases in 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 
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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 

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 and 3 

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 
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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 

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 
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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 

have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. It should be noted that 

both state plan types allow the state flexibility in assigning 

the emission performance obligations to its affected EGUs in the 

form of standards of performance as long as the required 

emission performance level is met. Both plan types harness the 

efficiencies of emission reduction opportunities in the 

interconnected electricity system and are fully consistent with 

the principles of cooperative federalism that underlie the Clean 

Air Act generally and CAA section 111(d) particularly. That is, 

both plan types achieve the emission performance requirements 

through the vehicle of a state plan, and provide each state 
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significant flexibility to take local circumstances and state 

policy goals into account in determining how to reduce emissions 

from its affected sources, as long as the plan meets minimum 

federal requirements. 

Both state plan types, and the standards of performance for 

the affected EGUs that the states will establish through the 

state plan process, are consistent with the applicable CAA 

section 111 provisions. A state has discretion in determining 

the appropriate measures to rely upon for its plan. The state 

may adopt measures that assure the achievement of the requisite 

CO2 emission performance rate or state goal by the affected EGUs, 

and is not limited to the measures that the EPA identifies as 

part of the BSER. 

 In this rulemaking, the EPA establishes reasonable 

deadlines for state plan submission. Under CAA section 

111(d)(1), state plans must “provide for implementation and 

enforcement” of the standards of performance, and under CAA 

section 111(d)(2), the state plans must be “satisfactory” for 

the EPA to approve them. In this rulemaking, the EPA is 

finalizing the criteria that the state plans must meet under 

these requirements. 
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 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 

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. 
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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 

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 
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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 contexts272 -- argued that 

the EPA’s 2005 interpretation was in error because it allowed 

the regulation of certain pollutants from source categories 

under CAA section 111(d) when those categories were also 

regulated for different pollutants under CAA section 112. 

Second, some commenters argued that the EPA’s previous 

 

272 For example, in the CAMR litigation (State of New Jersey v. 

EPA, No. 05-1097 (D.C. Cir.) , the joint brief filed by a group 

of intervenors and an amicus (including six states and the West 

Virginia Department of Environmental Protection, and Utility Air 

Regulatory Group and nine other industry entities) stated that 

the EPA had interpreted section 111(d) in light of the two 

different amendments and that the EPA’s interpretation was “a 

reasoned way to reconcile the conflicting language and the Court 

should defer to the EPA’s interpretation.” Joint Brief of State 

Respondent-Intervenors, Industry Respondent-Intervernors, and 

State Amicus, filed May 18, 2007, at 25. 
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interpretation of the House amendment (as originally represented 

in 2005 at 70 FR at 16029-30) was in error because it improperly 

read that amendment as focusing on whether a source category was 

regulated under CAA section 112 rather than on whether the air 

pollutant was regulated under CAA section 112, and that improper 

reading lead to an interpretation that was inconsistent with the 

structure and purpose of the CAA. 

In light of the comments, the EPA has reconsidered its 

previous interpretation of the Section 112 Exclusion and, in 

particular, considered whether the exclusion precludes the 

regulation under CAA section 111(d) of CO2 from power plants 

given that power plants are regulated for certain HAP under CAA 

section 112. On this issue, the EPA has concluded that the two 

differing amendments are not properly read as conflicting. 

Instead, the House amendment and the Senate Amendment should 

each be read to mean the same in 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. 
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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)).273 

The EPA’s revised interpretation is discussed below. 

1. Structure of the CAA and Pre-1990 Section 112 Exclusion 

The Clean Air Act sets out a comprehensive scheme for air 

pollution control, addressing three general categories of 

pollutants emitted from stationary sources: (1) criteria 

pollutants (which are addressed in sections 108-110); (2) 

hazardous pollutants (which are addressed under section 112); 

and (3) “pollutants that are (or may be) harmful to public 

health or welfare but are not or cannot be controlled under 

sections 108-110 or 112.” 40 Fed. Reg. 53,340 (Nov. 17, 1975). 

 

273 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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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 

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). 
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 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 

source emissions that pose any significant danger to public 

health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 274 

 

274 In subsequent CAA amendments, Congress has maintained this 

three-part scheme, but supplemented it with the Preservation of 
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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 

section 114) was described as covering pollutants that would not 

be controlled by the criteria pollutant provisions or the 

 

Significant Deterioration (PSD) program, the Acid Rain Program 

and the Regional Haze program. 
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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 

or subcategory’s hazardous pollutant emissions. 42 U.S.C. § 
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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 
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Large. Pub. L. No. 101-549, §§ 108(g) and 302(a), 104 Stat. 

2399, 2467, 2574 (1990). Where there is a conflict between the 

U.S. Code and the Statutes at Large, the latter controls. See 1 

U.S.C. §§ 112 & 204(a); Stephan v. United States, 319 U.S. 423, 

426 (1943) (“the Code cannot prevail over the Statutes at Large 

when the two are inconsistent”); Five Flags Pipe Line Co. v. 

Dep’t of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) (“[W]here 

the language of the Statutes at Large conflicts with the 

language in the United States Code that has not been enacted 

into positive law, the language of the Statutes at Large 

controls.”). 

 Second, the “conforming” label is irrelevant. A 

“conforming” amendment may be either substantive or nonsubstantive. Burgess v. United States, 553 U.S. 124, 135 

(2008). And while the House Amendment contains more words, it 

also qualifies as a “conforming” amendment under the definition 

in the Senate Legislative Drafting Manual, Section 126(b)(2) 

(defining “conforming amendments” as those “necessitated by the 

substantive amendments of provisions of the bill”). Here, both 

the House and Senate amendments were “necessitated by” Congress’ 

revisions to section 112 in the 1990 CAA Amendment, which 

included the deletion of old section 112(b)(1)(A). Thus, the 
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House’s amendment is no less “conforming” than the Senate’s, and 

the heading under which it was enacted (“Miscellaneous 

Guidance”) does not suggest any more importance than “Conforming 

Amendments.” In any event, courts gives full effect to 

conforming amendments, see Washington Hosp. Ctr. v. Bowen, 795 

F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate 

Amendment nor the House amendment can be ignored. 

Third, the legislative history of the Senate amendment 

supports the conclusion that the substitution of the updated 

cross-reference was not a mindless, ministerial decision, but 

reflected a decision to choose an update of the cross reference 

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 
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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, 

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. 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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context of other statutes using a variation of the word 

“regulate,” an agency must consider what is being regulated. 

See Rush Prudential HMO, Inc. v. Moran, 536 U.S. 355, 366 (2002) 

(It is necessary to “pars[e] . . . the ‘what’” of the term 

“regulates.”); UNUM Life Ins. Co. of Am. v. Ward, 526 U.S. 358, 

363 (1999) (the term “‘regulates insurance’ . . . requires 

interpretation, for [its] meaning is not plain.”). Here, one 

possible reading is that the phase modifies the words “a source 

category” without regard to what pollutants are regulated under 

section 112, which then presents the issue of what meaning to 

give to the phrase “a source category” 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 
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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 

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 
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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.275 

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 

 

275 In assessing any interpretation of section 111(d), EPA must 

consider how the three main programs set forth in the CAA work 

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory 

interpretation must account for . . . the broader context of the 

statute as a whole”) (quotation omitted). 
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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 

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).276

 

276 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 
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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 

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 

 

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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pollutants, but only with respect to HAP. Thus, it is reasonable 

to interpret the House amendment of the Section 112 Exclusion as 

only excluding the regulation of HAP emissions under CAA section 

111(d) and only when that source category is regulated under CAA 

section 112. We note that this first reasonable interpretation 

of the House amendment alone is the same as the 2005 CAMR 

interpretation of the two amendments combined: where a source 

category has been regulated under CAA section 112, a CAA section 

111(d) standard of performance cannot be established to address 

any HAP listed under CAA section 112(b) that may be emitted from 

that particular source category. See 70 FR 15994, 16029-30 

(March 29, 2005). 

Second, one could interpret the House amendment to mean 

that the Section 112 Exclusion always excludes the regulation of 

CAA section 112 pollutants, but does not exclude other 

pollutants, and the scope of the exclusion is the same 

regardless of whether the source category is subject to 

standards under CAA section 112. This interpretation of the 

House amendment reads the phrase “regulated under section 112” 

as modifying “air pollutant” rather than “source category” and 

reads the phrase “emitted by a source category” as having 

minimal import because it is the remnant of phrasing that was 
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originally intended to be an exclusion within CAA section 112 

for source categories regulated under section 111.277 A key 

distinction between this second reasonable interpretation and 

the first reasonable interpretation discussed above is that this 

second reasonable interpretation concludes that HAP can never be 

regulated under CAA section 111(d). 

 

277 Originally, when the House bill to amend the CAA was 

introduced in January 1989, it focused on amendments to control 

HAP. Of particular note, the amendments to CAA section 112 

included a provision that excluded regulation under section 112 

of “[a]ny air pollutant which is included on the list under 

section 108(a), or which is regulated for a source category 

under CAA section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA 

Legist. Hist. at 4046. In other words, the Section 112 Exclusion 

in CAA section 111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be called a 

“Section 111(d) Exclusion” in CAA section 112. This is 

significant because the “source category” phrasing in the 

original January 1989 text with respect to CAA section 111(d) 

makes sense, whereas the “source category” phrasing in the 1990 

House amendment does not. When referring to the scope of what is 

regulated under section 111(d), it makes sense to frame that 

scope with respect to source categories, because CAA section 111 

regulation begins with the identification of source categories 

under CAA section 111(b)(1)(A). By contrast, regulation under CAA

section 112 begins with the identification of HAP under CAA 

section 112(b); the listing of source categories under section 

112(c) is secondary to the listing of HAP. From this history, 

and in light of this difference between the scope of what is 

regulated in CAA sections 111 and 112, it is reasonable to 

conclude that the “source category” phrasing is a legacy from 

the original 1989 bill—that is, when converting the 1989 text 

into the Section 112 Exclusion that we see in the 1990 House 

amendment, the legislative drafters continued to use phrasing 

based on “source category” notwithstanding that this phrasing 

created a mismatch with the way that the scope of CAA section 

112 regulation is determined. 
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Third, one could interpret the House amendment to mean that 

the Section 112 Exclusion excludes all of the CAA section 112 

pollutants that have actually been regulated for at least one 

source category under CAA section 112, but does not exclude 

other pollutants (that is, pollutants that are not listed under 

CAA section 112). This third reasonable interpretation reads the 

phrase “a source category” as meaning “any” source category 

listed under section 112 and the phrase “regulated under section 

112” in light of the fact that a source category is “regulated 

under 112” with respect to HAP and not other pollutants. Thus, 

under this third reasonable interpretation of the House 

amendment, the scope of the Section 112 Exclusion does not cover 

non-HAP. 

These three interpretations share a number of common 

reasons why they are reasonable and avoid the issues discussed 

above. 

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 
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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 

pollutants, under more programs, more quickly.278 Conversely, the 

 

278 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 
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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 

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 

 

(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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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 

under CAA section 112. Thus, the EPA has the authority to 
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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 a CAA section 111(b) rulemaking that regulates CO2

emissions from new modified, and reconstructed EGUs. The 

promulgation of this rule 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 

“reconstruction,” which the implementing regulations go on to 
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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 a rulemaking under CAA section 111(b) 

for CO2 emissions from affected EGUs concurrently with this CAA 

section 111(d) rulemaking, which will provide the requisite 

predicate for applicability of CAA section 111(d).279

D. Definition of Affected Sources 

 

279 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 fossil 

fuel-fired electric utility steam generating unit or stationary 

combustion turbine that was in operation or had commenced 

construction as of January 8, 2014,280 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 

 

280 Under Section 111(a) of the CAA, determination of affected 

sources is based on the date that the EPA proposes action on 

such sources. January 8, 2014 is the date the proposed GHG 

standards of performance for new fossil fuel-fired EGUs were 

published in the Federal Register (79 FR 1430).
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turbine means any stationary combustion turbine which does not 

recover heat from the combustion turbine engine exhaust gases 

for purposes other than enhancing the performance of the 

stationary combustion turbine itself. Combined cycle combustion 

turbine means any stationary combustion turbine which recovers 

heat from the combustion turbine engine exhaust gases to 

generate steam that is used to create additional electric power 

output in a steam turbine. Combined heat and power (CHP) 

combustion turbine means any stationary combustion turbine which 

recovers heat from the combustion turbine engine exhaust gases 

to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric 

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 
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basis; (3) non-fossil units (i.e., units that are capable of 

combusting 50 percent or more non-fossil fuel) that have 

historically limited the use of fossil fuels to 10 percent or 

less of the annual capacity factor or are subject to a federally 

enforceable permit limiting fossil fuel use to 10 percent or 

less of the annual capacity factor; (4) stationary combustion 

turbines that are not capable of combusting natural gas (i.e., 

not connected to a natural gas pipeline); (5) are a combined 

heat and power 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.
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The rationale for applicability of this final rule is 

multi-fold. We had proposed that affected EGUs were those 

existing source fossil fuel-fired EGUs that met the 

applicability criteria for coverage under the final GHG 

standards for new fossil fuel-fired EGUs being promulgated under 

section 111(b). However, we are finalizing that States need not 

include certain units that would otherwise meet the CAA section 

111(b) applicability in this CAA section 111(d) emission 

guidelines. These include simple cycle turbines, certain nonfossil units, and certain combined heat and power units. The 

final 111(b) standards include applicability criteria for simple 

cycle combustion turbines, for reasons relating to 

implementation and minimizing emissions from all future 

combustion turbines. However, for the following reasons none of 

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. 
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Second, the vast majority of simple cycle turbines serve a 

specific need – providing power during periods of peak electric 

demand (i.e., peaking units). The existing block of simple cycle 

turbines are the only units that are able to start fast enough 

and ramp to full load quickly enough to serve as peaking units. 

If these units were to be used under building block 2 to 

displace higher emitting coal-fired units, they would no longer 

be available to serve as peaking units. Therefore, building 

block 2 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. 
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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 

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 sources from 

the two existing source categories for the affected EGUs, as 

listed in 40 CFR subpart Da and 40 CFR subpart KKKK, into a 

single location, 40 CFR subpart UUUU, for purposes of addressing 

the CO2 emissions from existing affected EGUs. The EPA is also 

codifying all of the requirements for the affected EGUs in a new 

subpart UUUU of 40 CFR part 60 and including all GHG emission 

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

turbines -- in that newly created subpart.281

e 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 sources into one location, subpart 

UUUU, will facilitate implementation of CO2 mitigation measures, 

such as shifting generation from higher to lower-carbon 

intensity generation among existing sources (e.g., shifting from 

utility boilers to NGCC units), and emission trading among 

sources in the source category. 

As discussed in the January 8, 2014 proposal for the CAA 

section 111(b) standards for GHG emissions from EGUs (79 FR 

1430), in 1971 the EPA listed fossil fuel-fired steam generating 

boilers as a new category subject to section 111 rulemaking, and 

in 1979 the EPA listed fossil fuel-fired combustion turbines as 

a new category subject to the CAA section 111 rulemaking. In the 

ensuing years, the EPA has promulgated standards of performance 

for the two categories and codified those standards, at various 

times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. 

 

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

rulemaking in subparts Da or KKKK. 
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In the January 8, 2014 proposal, the EPA proposed separate 

standards of performance for new sources in the two categories 

and proposed codifying the standards in the same Da and KKKK 

subparts that currently contain the standards of performance for 

conventional pollutants from those sources. In addition, the EPA 

co-proposed combining the two categories into a single category 

solely for purposes of the CO2 emissions from new construction of 

affected EGUs, and codifying the proposed requirements in a new 

40 CFR part 60 subpart TTTT. For the final standards of 

performance for new construction of affected EGUs, the EPA is 

codifying the final requirements in a new 40 CFR part 60 subpart 

TTTT. 

In this rulemaking, the EPA is combining the two source 

categories into a single source category for purposes of the CO2 

emissions from existing affected EGUs. Because the two source 

categories are pre-existing and the EPA would not be subjecting 

any additional sources to regulation, the combined source 

category is not considered a new source category that the EPA 

must list under CAA section 111(b)(1)(A). As a result, this 

final rule does not list a new source category under section 

111(a)(1)(A), nor does this final rule revise either of the two 

source categories – fossil fuel–fired electric utility steam 
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generating units and stationary combustion turbines – that the 

EPA has already listed under that provision. Thus, the EPA is 

not required to make a finding that the combined source category 

causes or contributes significantly to air pollution which may 

reasonably be anticipated to endanger public health or welfare. 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

 In the June 2014 proposal, the EPA proposed to determine 

that the best system of emission reduction adequately 

demonstrated (BSER) for reducing CO2 emissions from existing EGUs 

was a combination of measures –- (1) increasing the operational 

efficiency of existing coal-fired steam EGUs, (2) substituting 

increased generation at existing NGCC units for generation at 

existing steam EGUs, (3) substituting generation from low- and 

zero-carbon generating capacity for generation at existing 

fossil fuel-fired EGUs, and (4) increasing demand-side energy 

efficiency to reduce the amount of fossil fuel-fired generation 

–- which we categorized as four “building blocks.” As an 

alternative to the proposed building blocks 2, 3, and 4, the EPA 

also identified reduced generation in the amount of those 

building blocks as part of the BSER. These measures are not the 

only approaches EGUs can take to reduce CO2, but are those that 
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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 

across multiple sources, reflecting the fact that each EGU’s 

function is interdependent with the function of other EGUs. Each 

building block is a proven approach for reducing emissions from 

the affected source category that is appropriate in this 

pollutant- and industry-specific context. Each building block 

also encompasses a variety of actions that individual affected 

sources may take, including (i) direct investment in efficiency 

improvements and in lower- and zero-carbon generation, (ii) 

cross-investment in these activities through mechanisms such as 
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emissions trading or other multi-unit compliance approaches, 

where the state-established standards of performance to which 

sources are subject incorporate or allow such approaches, and 

(iii) reduction of higher-carbon generation. 

 With attention to costs, electricity rates, and the 

importance of ensuring continued reliability of electricity 

supplies, the individual building blocks and the overall BSER 

have been defined not at the maximum possible degree of 

stringency but at a reasonable degree of stringency designed to 

appropriately balance consideration of the various BSER factors. 

Additional, non-building block specific aspects of the BSER 

quantification methodology discussed below are similarly 

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, but nevertheless, as required by the CAA, will result 

in meaningful reductions in CO2 emissions from this sector. The 

wide range of actions encompassed in the building blocks, and a 

further wide range of possible emissions-reducing actions not 

included in the BSER but nevertheless available to help with 

compliance, ensure that the BSER is achievable by individual 

affected sources as well. 
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 The final BSER incorporates certain changes from the 

proposed rule, reflecting the EPA’s 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; 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, 

the final rule also provides weighted-average state-specific 

goals that a state may choose as an alternative method for 

complying with its obligation to set standards of performance 
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for its affected EGUs -– an alternative, that is, to adopting 

the nationwide subcategory-based CO2 emission performance rates 

as the standard of performance for its affected EGUs. The change 

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, 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.282

We received comments on our proposed interpretation, and in 

light of those comments, in this final rule, we are clarifying 

our interpretation in certain respects. We discuss our 

interpretation below.283 

 

282 79 FR 1430, 1462 (January 8, 2014). 283 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 
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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 

 

except to the extent that they reflect distinctions between new 

and existing sources. For example, as discussed in the section 

111(b) rule, the legislative history indicates that Congress 

intended that the BSER for new industrial facilities, which were 

expected to have lengthy useful lives, would include the most 

advanced pollution controls available, but Congress had a 

broader conception of the BSER for existing facilities. 
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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.284 

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 for the states 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.285 

Following the EPA’s promulgation of emission guidelines, 

each state must determine the standards of performance for its 

 

284 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). 

285 See Sierra Club v. Costle, 657 F.2d at 330 (“The language of 

section 111 not only authorizes variable control but also gives 

EPA authority when determining the best technological system to 

weigh cost, energy, and environmental impacts in the broadest 

sense at the national and regional levels and over time as 

opposed to simply at the plant level in the immediate present. ... 

The standard is, after all, a national standard with long-term 

effects.”). 
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sources, which the EPA’s regulations terms “designated 

facilities.”286 A state has broad discretion in doing so. CAA 

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

State in applying a standard of performance to any particular 

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

remaining useful life of the ... source....”287 In addition, 

under CAA section 116, the state is authorized to set a standard 

of performance for any particular source that is more stringent 

than the emission limit contained in the EPA’s emission 

guidelines.288 Thus, for any particular source, a state may 

apply a standard of performance that is either more stringent or 

less stringent than the performance level in the emission 

 

286 40 C.F.R. § 60.24(b)(3). 287 The EPA’s regulations, promulgated prior to enactment of the 

“remaining useful life” provision of section 111(d)(1), provide: 

“Unless otherwise specified in the applicable subpart on a caseby-case basis for particular designated facilities, or classes 

of facilities, States may provide for the application of less 

stringent emission standards or longer compliance schedules than 

those otherwise required” by the corresponding emission 

guideline. 40 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. 288 In addition, CAA section 116 authorizes the state to set 

standards of performance for all of its sources that, together, 

are more stringent than the EPA’s emission guidelines. 
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guidelines, as long as, in total, the state’s sources achieve at 

least the same degree of emission limitation as included in the 

EPA’s emission guidelines. The states must include the standards 

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

EPA for review.289 Under CAA section 111(d)(2)(A), the EPA 

approves state plans as long as they are “satisfactory.,” 

As noted in the January 2014 proposal and discussed in more 

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

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.290 In addition, although the D.C. 

 

289 40 C.F.R. § 60.23. 290 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. 
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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 2011,291 through which the Court has developed a 

body of case law that interprets the term “standard of 

 

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard (i) be based 

on, in lieu of the “best system of emission reduction ... 

adequately demonstrated,” the “best technological system of 

continuous emission reduction ... adequately demonstrated;” and 

(ii) require a percentage reduction in emissions. In addition, 

in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 

consider “any nonair quality health and environment impact and 

energy requirements.” 

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction ... adequately demonstrated.” 

This 1990 CAAA version is the current definition, which is 

applicable at present. Even so, because parts of the definition 

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. 

291 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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performance.” 

c. Key elements of interpretation. The emission guidelines 

promulgated by the Administrator must include emission 

limitations that are “achievable” by the source category by 

application of a “system of emission reduction” that is 

“adequately demonstrated” and that the EPA determines to be the 

“best,” “taking into account” the factors of “cost ... nonair 

quality health and environmental impact and energy 

requirements.” The D.C. Circuit has stated that in determining 

the “best” system, the EPA must also take into account “the 

amount of air pollution”292 reduced and the role of 

“technological innovation.”293 The Court has emphasized that the 

EPA has discretion in weighing those various factors.294,295

 

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

1981). 

293 See Sierra Club v. Costle, 657 F.2d at 347. 294 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999).

295 Although CAA section 111(a)(1) may be read to state that the 

factors enumerated in the parenthetical are part of the 

“adequately demonstrated” determination, the D.C. Circuit’s 

caselaw appears to treat them as part of the “best” 

determination. See Sierra Club v. Costle, 657 F.2d at 330 

(recognizing that CAA section 111 gives the EPA authority “when 

determining the best technological system to weigh cost, energy, 

and environmental impacts”). Nevertheless, it does not appear 

that those two approaches would lead to different outcomes. See, 

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

Cir. 1999) (rejecting challenge to the EPA’s cost assessment of 
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Our overall approach to determining the BSER and emission 

guidelines, which incorporates the various elements, is as 

follows: In developing an emission guideline, we generally 

engage in an analytical approach that is similar to what we 

conduct under CAA section 111(b) for new sources. First, we 

identify “system[s] of emission reduction” that have been 

“adequately demonstrated” for a particular source category. 

Second, we determine the “best” of these systems after 

evaluating the amount of reductions, costs, any nonair health 

and environmental impacts, energy requirements, and, in the 

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

formulation of the BSER with the above noted factors, and then, 

in the alternative, we apply a formulation of the BSER with 

those same factors plus the advancement of technology). And 

third, we select an achievable emission limit –- here, the 

emission performance standard -- based on the BSER.296 In 

contrast to subsection (b), however, subsection (d)(1) assigns 

 

the “best demonstrated system”). In this rule, the EPA treats 

the factors as part of the “best” determination, but, as noted, 

even if the factors were part of the “adequately demonstrated” 

determination, our analysis and outcome would be the same. 

296 See, e.g., Oil and Natural Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

pollutants Reviews, 77 F.R. 49490, 49494 (Aug. 16, 2012) 

(describing the three-step analysis in setting a standard of 

performance). 
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to the states, not the EPA, the obligation of setting standards 

of performance for the affected sources. Thus, we also take into 

account whether states can establish standards of performance 

that can implement the measures under consideration for 

inclusion in the BSER. As discussed below in the following 

subsection, in examining the range of reasonable options for 

states to consider in setting standards of performance under 

these guidelines, we identified a number of considerations, 

including the interconnected operations of the affected sources 

and the global nature of the CO2 pollutant. And third, we select 

an achievable emission limit –- here, the emission performance 

standard -- based on the BSER.297 

The remainder of this subsection discusses the various 

elements in our general analytical approach. 

(1) System of emission reduction. 

 

297 See, e.g., Oil and Natural Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

pollutants Reviews, 77 F.R. 49490, 49494 (Aug. 16, 2012) 

(describing the three-step analysis in setting a standard of 

performance). 
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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.”298 With 

this definition, the phrase “system of emission reduction” takes 

a broad meaning: a set of things that work together to reduce 

emissions. The EPA interprets this phrase to carry an important 

limitation: because the emission guidelines for the existing 

sources must reflect “the degree of emission limitation 

achievable through the application of the best system of 

emission reduction ... adequately demonstrated,” the system must 

be limited to things that can be implemented -– “appl[ied]” -- 

by the sources themselves, that is, as a practical matter, by 

actions taken by the owners or operators of the sources. As we 

discuss below, this definition is sufficiently broad to include 

the building blocks. 

(2) “Adequately demonstrated.” 

Under section 111(a)(1), in order for a “system of emission 

reduction” to serve as the basis for an “achievable” emission 

 

298 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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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.”299 It does not mean that the system “must be 

in actual routine use somewhere.”300 Rather, the Court has said, 

“[t]he Administrator may make a projection based on existing 

technology, though that projection is subject to the restraints 

of reasonableness and cannot be based on ‘crystal ball’ 

inquiry.”301 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.”302 Ultimately, the analysis “is partially dependent on 

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

 

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

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 300 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). 

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

Cir. 1973) (citations omitted). 

302 Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 
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have to be available.”303 Unlike for CAA section 111(b) standards 

that are applicable immediately after the effective date of 

their promulgation, under CAA section 111(e), compliance with 

CAA section 111(d) standards may be set sometime in the future. 

This is due, in part, to the period of time for states to submit 

state plans and for the EPA to act on them. 

(3) “Best.” 

In determining which adequately demonstrated system of 

emission reduction is the “best,” the EPA considers the 

following factors: 

(a) Costs. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “the cost of achieving” the required emission 

reductions. As described in the January 2014 proposal,304 in 

several cases the D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard in various ways, stating 

that the EPA may not adopt a standard the cost of which would be 

“exorbitant,”305 “greater than the industry could bear and 

 

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

Cir. 1973) (citations omitted). 

304 79 FR 1430, 1464 (January 8, 2014). 305 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999). 

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survive,”306 “excessive,”307 or “unreasonable.”308 In this 

rulemaking, we find that the costs considered are reasonable and 

well within the legal boundaries established by this caselaw.309 

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 

 

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

1975). 

307 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 308 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 309 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted: 

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business. 

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is “available” should 

not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach. 

S. Comm. Rep. No. 91-1196 at 16. 

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standard, so

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practicable control technology be considered by the owner of a 

large new source of pollution as a normal and proper expense of 

doing business.”310 See Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d 427, 440 (D.C. Cir. 1973);311 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”).312 

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis. 

(b) Non-air health and environmental impacts. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “any nonair quality health and environmental 

 

310 1977 House Committee Report at 184. 311 The costs for these standards were described in the 

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

5769 (March 21, 1972). 

312 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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impact” in determining the BSER. As the D.C. Circuit has 

explained, this requirement makes explicit that a system cannot 

be “best” if it does more harm than good due to cross-media 

environmental impacts.313

(c) Energy considerations. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “energy requirements.” As discussed below, the EPA 

may consider energy requirements on both a source-specific basis 

and a sector-wide, region-wide, or nationwide basis. Considered 

on a source-specific basis, “energy requirements” entails, for 

example, the impact, if any, of the system of emission reduction 

on the source’s own energy needs. 

(d) Amount of emissions reductions. 

In the proposed rulemakings for this rule and the 

associated section 111(b) rule, we noted that although the 

definition of “standard of performance” does not by its terms 

identify the amount of emissions from the category of sources or 

the amount of emission reductions achieved as factors the EPA 

must consider in determining the “best system of emission 

 

313 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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reduction,” the D.C. Circuit has stated that the EPA must do so. 

See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) 

(“we can think of no sensible interpretation of the statutory 

words “best ... system” which would not incorporate the amount of 

air pollution as a relevant factor to be weighed when 

determining the optimal standard for controlling ... 

emissions”).314 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. 

 

314 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.” 
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 (e) Sector- or nationwide component of factors in 

determining the BSER. 

As discussed in the January 2014 proposal for the section 

111(b) rulemaking and the proposal for this rulemaking, another 

component of the D.C. Circuit’s interpretations of CAA section 

111 is that the EPA may consider the various factors it is 

required to consider on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.315 The D.C. Circuit based this interpretation – which 

it made in the 1981 Sierra Club v. Costle case, which concerned 

the NSPS for new power plants -- on a review of the legislative 

history, stating, 

The Conferees defined the best technology in terms of 

“long-term growth,” “long-term cost savings,” 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 111.316 

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, 

 

315 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351). 316 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).

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including prices and utilization of coal 

reserves, 
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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.317

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. 

(4) Achievability of the emission limitation in the 

emission guidelines. 

Before discussing the requirement under section 111(d) that 

the emission limitation in the emission guidelines must be 

“achievable,” it is useful to discuss the comparable requirement 

under section 111(b) for new sources. For new sources, CAA 

section 111(b)(1)(B) and (a)(1) provides that the EPA must 

 

317 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. 

Costle before the Chevron case was decided in 1984, the D.C. 

Circuit’s decision could be justified under either Chevron step 

1 or 2. 79 FR 1430, 1466 (January 8, 2014). 
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establish “standards of performance,” which are standards for 

emissions that reflect the degree of emission limitation that is 

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

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

technology can reasonably be projected to be available to an 

individual source at the time it is constructed that will allow 

it to meet the standard.318 Moreover, according to the Court, 

”[a]n achievable standard is one which is within the realm of 

the adequately demonstrated system’s efficiency and which, while 

not at a level that is purely theoretical or experimental, need 

not necessarily be routinely achieved within the industry prior 

to its adoption.”319 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.’”320

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 

 

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

1981). 

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

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 320 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 

1980). 
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on by the agency are representative of potential industry-wide 

performance, given the range of variables that affect the 

achievability of the standard.”321

In this rulemaking, we are taking the same approach for the 

emission limitation that the EPA identifies in the emission 

guidelines. For existing sources, section 111(d)(1) requires the 

EPA to establish requirements for state plans that, in turn, 

must include “standards of performance.” Through long-standing 

regulations322 and consistent practice, the EPA has interpreted 

this provision to require the EPA to promulgate emission 

guidelines that determine the BSER for a source category and 

that identify the amount of emission limitation achievable by 

application of the BSER. 

The EPA has promulgated these emission guidelines on the 

basis that the existing sources can achieve the limitation, even 

though the State retains discretion to apply standards of 

 

321 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). 322 40 C.F.R. § 60.21(e). 
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performance to individual sources that are more or less 

stringent. 

(a) Technical feasibility. 

As indicated in the proposed rulemakings for this rule and 

the associated section 111(b) rule, the requirement that the 

emission limitation in the emission guidelines be “achievable” 

based on the “best system of emission reduction ... adequately 

demonstrated” indicates that the technology or other measures 

that the EPA identifies as the BSER must be technically 

feasible. See 79 FR 1430, 1463 (January 8, 2014). At least in 

some cases, in determining whether the emission limitation is 

achievable, it is useful to analyze the technical feasibility of 

the system of emission reduction, and we do so in this 

rulemaking. 

(5) Expanded use and development of technology. 

The D.C. Circuit has long held that Congress intended for 

CAA section 111 to create incentives for new technology and 

therefore that the EPA is required to consider technological 

innovation as one of the factors in determining the “best system 

of emission reduction.” See Sierra Club v. Costle, 657 F.2d at 

346-47. The Court has grounded its reading in the statutory 
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text.323 In addition, the Court’s interpretation finds firm 

support in the legislative history.324 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);325 (ii) the 

expanded use of the best demonstrated technology;326 and (iii) 

 

323 Sierra Club v. Costle, 657 F. 2d at 346 (“Our interpretation 

of section 111(a) is that the mandated balancing of cost, 

energy, and nonair quality health and environmental factors 

embraces consideration of technological innovation as part of 

that balance. The statutory factors which EPA must weigh are 

broadly defined and include within their ambit subfactors such 

as technological innovation.”). 

324 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”). 

325 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”). 

326 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”). 
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the development of emerging technology.327 Even if the EPA were 

not required to consider technological innovation as part of its 

determination of the BSER, it would be reasonable for the EPA to 

consider it, either because technological innovation may be 

considered an element of the term “best,” or because the term 

“best system of emission reduction” is ambiguous as to whether 

technological innovation may be considered, and it is reasonable 

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. 

(6) EPA discretion. 

The D.C. Circuit has made clear that the EPA has broad 

discretion in determining the appropriate standard of 

performance under the definition in CAA section 111(a)(1), 

quoted above. Specifically, in Sierra Club v. Costle, 657 F.2d 

 

327 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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298 (D.C. Cir. 1981), the Court explained that “section 111(a) 

explicitly instructs the EPA to balance multiple concerns when 

promulgating a NSPS,”328 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

the standard.”329 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 111.330 

d. Approach to the source category and subcategorizing. Section 

111 requires the EPA first to list source categories that may 

 

328 Sierra Club v. Costle, 657 F.2d at 319. 329 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). 

330 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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reasonably be expected to endanger public health or welfare and 

then to regulate new sources within each such source category. 

Section 111(b)(2) grants the EPA discretion whether to 

“distinguish among classes, types, and sizes within categories 

of new sources for the purpose of establishing [new source] 

standards,” which we refer to as “subcategorizing.” Section 

111(d)(1), in conjunction with section 111(a)(1), simply 

requires the EPA to determine the BSER, does not prescribe the 

method for doing so, and is silent as to whether the EPA may 

subcategorize. The EPA interprets this provision to authorize 

the EPA 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.331

 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, 

 

331 40 CFR 60.22(b)(5). 
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as part of its section 111(d) plan, a state retains great 

flexibility in assigning standards of performance to its 

affected EGUs. Thus, the state may, if it wishes, impose 

different emission reduction obligations on different sources, 

as long as the overall level of emission limitation is at least 

as stringent as the emission guidelines. 

2. The BSER for this Rule – Overview 

a. Summary. This section describes the EPA’s overall approach to 

establishing the BSER. This rule, promulgated under CAA section 

111(d), establishes emission guidelines for states to use in 

establishing standards of performance for affected EGUs, and the 

BSER is the central determination that the EPA must make in 

formulating the guidelines. 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 and operating under the standards of 

performance established for them by the states, can implement to 

reduce their emissions to an appropriate amount, and that meet 

the other requirements for the BSER including, for example, cost 
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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. 

The second perspective considers the affected EGUs 

individually, and treats the BSER as the set of actions that an 

EGU, operating under a standard of performance established by 

its state, may take to achieve the applicable performance rate, 

if the state adopts that rate as the standard of performance and 

applies it to the EGUs in its jurisdiction, or to achieve the 

equivalent mass-based limit, and that meet the 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 

source-category and individual-source perspectives for this rule 

is the substitution of non-emitting generation for CO2-emitting 

generation. This measure involves two distinct actions: 
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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 

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 

standards of performance on their sources that implement the CO2

emissions performance rates, or, as an alternative method of 

compliance, 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.332 Each state has flexibility in how it 

 

332 The approaches that states may take in their plans are discussed in section VIII. 
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assigns the emission limitations to its affected EGUs –- and in 

fact, the state can be more stringent than the guidelines 

require –- but one of the state’s choices is to convert the CO2

emission performance rates into standards of performance –- 

which may incorporate emissions trading –- for each of its 

affected EGUs. If a state does so, then the affected EGUs may 

achieve their emission limits by taking the actions that qualify 

as the BSER. Since the BSER and, in this case its constituent 

elements, reflect the 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 -- 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.333 As noted above, the BSER 

determined through this process can be described from two 

 

333 Other sections in this preamble describe how EPA calculated 

the CO2 emission performance rates based on the BSER. 
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perspectives. Viewed from the source-category perspective, the 

EPA is identifying the BSER as a well-established set of 

measures that have been used by EGUs for many years to achieve 

various business and policy purposes, and have been used in 

recent years for the specific purpose of reducing EGUs’ CO2

emissions, and that are appropriate to the global nature of 

carbon pollution and afforded by the highly integrated nature of 

the utility power sector. As also noted, we evaluated these 

measures with a view to the states’ obligation to establish 

standards of performance and included in our BSER determination 

consideration of the range of options available for states to 

employ in establishing those standards of performance. These 

measures include (i) increasing the operational efficiency 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 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 
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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 crossinvestment by individual affected EGUs in emission rate 

improvements or emission reduction activities at other locations 

on the interconnected electricity system. The range of 

mechanisms includes bilateral investment of various kinds; the 

issuance and purchase of emission rate credits representing the 

emissions-reducing effects of specific activities, where 

available under state plans; more general emissions trading 

using rate-based credits or mass-based allowances (as discussed 

in section V.A.2.f. below), where the affected EGUs are 

operating under standards of performance that incorporate 

emissions trading; and other multi-unit compliance approaches 

such as averaging or bubbling, where available under state 

plans.334

Viewed from the individual-source perspective, the EPA is 

identifying the BSER as a menu of actions -- all of which fall 

 

334 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 operating under a 

standard of performance that incorporates emissions trading can 

implement by means of purchasing rate-based emission credits or 

mass-based emission allowances from other affected EGUs, since 

the effect of the purchase would be the same as achieving the 

other listed actions through direct means, and (vi) all affected 

EGUs can implement through other multi-unit compliance 

approaches such as averaging or bubbling, where available under 

state plans.335 

 

335 Again, conditions for the use of these mechanisms under 

various state plans are discussed in section VIII. 
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Importantly, viewed from either the source-category 

perspective or the individual-source perspective, affected EGUs 

also have available numerous other measures that are not 

included in the BSER but that could materially help the EGUs 

achieve their emission limits and thereby provide compliance 

flexibility. Examples include, among numerous other approaches, 

investment in demand-side energy efficiency, 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 as informed by the 

information and data provided by commenters and our further 

evaluation. What follows is the EPA’s final determination. 

As described in the proposal, to determine the BSER, the 

EPA began by considering the characteristics of CO2 pollution and 

the utility power sector. Not surprisingly, whenever the EPA 

begins the regulatory process under section 111, it initially 

undertakes these same inquiries and then proceeds to fashion the 
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rule to fit the industry. For example, in 1979, the EPA 

finalized new standards of performance to limit emissions of SO2

from new, modified, and reconstructed EGUs.336 In assessing the 

final SO2 standard, the EPA carried out extensive analyses of a 

range of alternative SO2 standards “to identify environmental, 

economic, and energy impacts associated with each of the 

alternatives considered at the national and regional levels.”337

In identifying the best system underlying the final standard, 

the EPA evaluated “coal cleaning and the relative economics of 

FGD [flue gas desulfurization] and coal cleaning” together as 

the “best demonstrated system for SO2 emission reduction.”338 The 

EPA also took into account the unique features of power 

 

336 The need for new standards was due in part to findings that 

in 1976, steam electric generating units were responsible for 

“65 percent of the SO2 ... emissions on a national basis.” 44 FR 

33580, 33587 (June 11, 1979). The EPA explained that [u]nder the 

current performance standards for power plants, national SO2

emissions are projected to increase approximately 17 percent 

between 1975 and 1995. Impacts will be more dramatic on a 

regional basis.” Id. Thus, “[o]n January 27, 1977, EPA announced 

that it had initiated a study to review the technological, 

economic, and other factors needed to determine to what extent 

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

revised.” Id. at 33587-33588. 337 44 FR 33580, 33582 (June 11, 1979). 338 44 FR 33580, 33593. The EPA considered an investigation by 

the U.S. Department of the Interior regarding the amount of 

sulfur that could be removed from various coals by physical coal 

cleaning. Id. at 33593. 
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transmission along the interconnected grid and the unique 

commercial relationships that rely on those features.339=

Similarly, in 1996, the EPA finalized section 111(b) 

standards and 111(d) emission guidelines to ensure that certain 

municipal solid waste (MSW) landfills controlled landfill gases 

to the level achievable through application of the BSER.340 EPA’s 

identification of this BSER was critically influenced by the 

“unique emission pattern of landfills.”341 Unlike “typical 

stationary source[s],” which only generate emissions while in 

operation, MSW landfills can “continue to generate and emit a 

significant quantity of emissions” long after the facility has 

 

339 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 

340 61 FR 9905, 9905 (March 12, 1996). In the rule, the EPA 

referred to the BSER for both new and existing MSW landfills as 

“the best demonstrated system of continuous emission reduction,” 

as well as the “BDT”—short for “best demonstrated technology.” 

See, e.g., id. at 9905–07, 9913–14. 341 61 FR 9905, 9908; see 56 FR 24468, 24478 (May 30, 1991) 

(explaining at proposal that because landfill-gas emission rates 

“gradually increase” from zero after the landfill opens, and 

“gradually decrease” from peak emissions after closure, the 

EPA’s identification of the BSER for landfills inherently 

requires a determination of “when controls systems must be 

installed and when they may be removed”).
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closed or otherwise stopped accepting waste.342 In recognition of 

this salient and unique characteristic of landfills, the EPA set 

the BSER based on an emission-reducing system of gas collection 

and control that remained in place as long as emissions remained 

above a certain threshold -- even after the regulated landfill 

had permanently closed.343 The EPA acknowledged that for some 

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

below the cutoff.344

For this rule, 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 the fact that the 

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. 

 

342 See U.S. EPA, Municipal Solid Waste Landfills, Volume 1: 

Summary of the Requirements for the New Source Performance 

Standards and Emission Guidelines for Municipal Solid Waste 

Landfills, Docket No. EPA-453R/96-004 at 1-3 (February 1999). 343 61 FR 9905, 9907–08. 344 61 FR 9905, 9908.
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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.”345 The core function of providing reliable electricity 

service is carried out not by individual electricity generating 

units but by the complex machine as a whole. Important 

subsidiary functions such as management of costs and management 

of environmental impacts are also carried out to a great extent 

on a multi-unit basis rather than an individual-unit basis. 

Generation from one generating unit can be and routinely is 

 

345 S. Massoud Amin, “Securing the Electricity Grid,” The Bridge, 

Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A Journey 

Through the Heart of Our Electrified World 1 (2007). 
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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.346 A survey of integrated resource plans (IRPs), 

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

taking actions to reduce emissions of both non-GHG air 

pollutants and GHGs.347 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 

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

using those measures to replace their higher-emitting 

 

346 Demand-side energy efficiency measures have also increased, 

and the projected future trends are for continued increase. 

347 The IRPs typically also indicate planned investment in 

demand-side energy efficiency. 
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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.348 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 

 

348 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.349

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 reduces emissions. 

Some of these programs also include emissions trading among the 

power plants. 

In this rule, when evaluating the types and amounts of 

measures that the source category can take to reduce CO2

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 

 

349 Many of these programs are discussed in section V.B. 
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higher-carbon generation toward lower- and zero-carbon 

generation. These factors strongly support consideration of 

emission reduction approaches that focus on the machine as a 

whole –- that is, the overall source category –- by shifting 

generation from dirtier to cleaner sources in addition to 

emission reduction approaches that focus on improving the 

emission rates of individual sources. 

The factors just discussed that support consideration of 

emission reduction measures at the source-category level 

likewise strongly support consideration of mechanisms such as 

emissions trading and other multi-unit compliance approaches, 

especially since, as discussed in section VIII, the states will 

have every opportunity to design their section 111(d) plans to 

allow the affected EGUs in their respective jurisdictions to 

employ emissions trading or other multi-unit compliance 

approaches to achieve the standards of performance established 

in those plans. In short, as discussed in more detail in section 

V.A.2.f. below, it is entirely feasible for states to establish 

standards of performance that incorporate emissions trading, and 

it is reasonable to expect that states will do so. These 

approaches lower overall costs, add flexibility, and make it 

easier for individual sources to address pollution control 

Formatted: Highlight

Commented [A9]: It would be helpful to describe when trading 

is and is not necessary for sources to be able to secure compliance 

Formatted: Highlight
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objectives. To the extent that the purchase of an emissions 

credit or allowance represents the purchase of surplus emission 

reductions by an emitting source, emissions trading represents, 

in effect, the investment in pollution control by the purchasing 

source, notwithstanding that the control activity may be 

occurring at another source. As noted above, the utility power 

sector has a long history of using the “complex machine” to 

address objectives and constraints of various kinds. When 

afforded the opportunity to address environmental objectives on 

a multi-unit basis, the industry has done so. Congress and the 

EPA have selected emissions trading approaches when addressing 

regional pollution from the utility power sector contributing to 

problems such as acid precipitation and interstate transport of 

ozone and particulate matter. Similarly, states have selected 

market-based approaches for their own programs to address 

regional and global pollutants. The industry has readily adapted 

to that form of regulation, taking advantage of the flexibility 

and incorporating those programs into the planning and operation 

of the “machine.” Further reinforcing our conclusion that 

reliance on trading is appropriate is the extensive interest in 

using such mechanisms that states and utilities demonstrated 

through their formal comments and in discussions during the 
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outreach process. The role of emissions trading is discussed 

further in section V.A.2.f. below. 

This entire review has made clear that there are numerous 

measures that, alone or in various combinations, merit analysis 

for inclusion in the BSER. The review has also made clear that 

the global nature of CO2 pollution and the unique, interconnected 

manner in which affected EGUs and other generating sources 

operate within the electricity sector make certain types of 

measures and mechanisms available and appropriate for 

consideration as the BSER for this rule that would not be 

appropriate for other pollutants and other industrial sectors. 

For purposes of this discussion, the measures can be categorized 

in terms of the essential characteristics of the four building 

blocks described in the proposal: Measures that (i) reduce the 

CO2 emission rate at the unit, (ii) substitute generation from 

existing lower-emitting fossil fuel-fired units for generation 

from higher-emitting fossil fuel-fired units, (iii) substitute 

generation from new low- or zero-emitting generating capacity, 

especially renewable energy, for generation from fossil fuelfired units, and (iv) increase demand-side energy efficiency to 

avoid generation from fossil fuel-fired units. In the proposal, 

we described our evaluations of various measures in each of 
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these categories. In this rule, with the benefit of comments, we 

have refined our evaluation of which specific measures should 

comprise the first three building blocks, and, for reasons 

discussed below, we have determined that the fourth building 

block, demand-side energy efficiency, should not be included in 

the BSER in these guidelines. 

The measures are discussed more fully below, but it should 

be noted here that because of the integrated nature of the 

utility power sector, in which individual EGUs’ operations 

intrinsically depend on the operations of other generators, 

coupled with the sector’s high degree of planning and 

reliability safeguards, the measures in the second and third 

categories, which involve generation shifts to lower- and zeroemitting sources, may occur 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 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 
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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.350 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. 

As discussed below, these latter mechanisms are well within the 

realm of consideration for the standards of performance states 

can choose to apply to their EGUs and hence, are entirely 

appropriate for EPA to consider in evaluating these measures in 

the course of making its BSER determination. 

c. State establishment of standards of performance and source 

compliance. Before identifying in detail the measures that the 

BSER comprises, it is useful to describe the process by which 

the states establish the standards of performance with which the 

affected EGUs must comply, and the implications for the sources 

 

350 The same is true for demand-side energy efficiency measures. 
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that will be operating subject to those standards of 

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

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

performance rates that represent the BSER and, pursuant to 

subsection 111(d)(1), requiring states to establish standards of 

performance for affected EGUs in order to implement those rates. 

States, of course, could simply impose those rates on each 

affected EGU in their respective jurisdictions, but we are also 

offering states alternative approaches to carrying out their 

obligations. For purposes of defining these alternatives and 

facilitating states’ efforts to formulate compliance plans 

encompassing maximum flexibilities, we are aggregating the 

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

has the option of setting specific standards of performance for 

its EGUs such that the emission limitations from the EGUs 

operating under those standards of performance together meet the 

performance rates or the state goal. To do this, the state must 

adopt a plan that establishes the EGUs’ standards of performance 

and that implements and enforces those standards. 

Each state has significant flexibility in several respects. 

For example, as mentioned, a state may impose standards of 

performance on its steam EGU sources and on its combustion 

Commented [A10]: Reflect? 
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turbine sources that simply reflect the respective CO2 emission 

performance rates for those subcategories set in the emission 

guidelines. Alternatively, a state may impose standards with 

differing degrees of stringency on various sources, and, in 

fact, may be more stringent overall than its state goal 

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). Moreover, a state may make 

those limits tradable or authorize other multi-unit 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 nonBSER measures are available to the individual affected EGUs for 

compliance flexibility. For example, if an individual source 

chooses to adopt building block 3 by both investing in lower- or 

zero-emitting generation and reducing its own generation, both 

those actions will be accounted for in its emission rate and 

both will therefore help the source meet its rate-based limit. 
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If the same individual source takes the same actions but is 

subject to a mass-based limit, the action of reducing its 

generation will directly count in helping the source meet its 

own mass-based limit but the action of investing in cleaner 

generation will not. However, the investment in lower-or zeroemitting generation by that source and other sources 

collectively will help the overall source category achieve the 

emission limits consistent with the BSER and in doing so will 

make it easier for that source and other sources collectively to 

meet their mass-based limits. 

In instances where a state establishes standards of 

performance that incorporate emissions trading, the tradable 

credits or allowances can serve as a medium through which 

affected EGUs can invest in any emission reduction measure. 

d. Identification of the BSER measures – the source-category 

perspective. We 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 
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includes a set of measures that the EPA determined would result 

in improvements in heat rate at coal-fired steam EGUs in the 

amount of 6 percent on average, and the EPA proposed that this 

set of measures qualifies as a component of the BSER. In this 

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

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

below, based on 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 identifying the heat rate improvements 

achievable by coal-fired steam EGUs as 4.3 percent for the 

Eastern Interconnection, 2.1 percent for the Western 

Interconnection, and 2.3 percent for the Texas Interconnection. 

The refinements are based, in significant part, on the numerous 

comments we received on these points, especially those from 

states and utilities. 

 These heat rate improvement measures include best practices 

such as improved staff training; boiler chemical cleaning; 
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cleaning air preheater coils, and use of various kinds of 

software, as well as equipment upgrades such as turbine 

overhauls. These are measures that the owner/operator of an 

affected coal-fired steam EGU may take that would have the 

effect of reducing the amount of CO2 the source emits per MWh. As 

a result, these measures would help the source achieve an 

emission limit expressed as either an emission rate limit or as 

a mass limit. We note again that in the context both of the 

integrated electricity system and of available and anticipated 

state approaches to setting standards of performance, emissions 

trading or other multi-unit compliance approaches could be used 

as mechanisms through which one affected source could invest in 

heat rate improvements at another source. We note this aspect 

below in describing the individual-source perspective of the 

BSER and discuss it in more detail in section V.A.2.f. 

These heat rate improvements are a low-cost option that fit 

the criteria for the BSER, except that they lead to only small 

emission reductions for the source category—or could increase 

emissions if they led to increases in utilization. Given the 

magnitude of the environmental problem and projections by 

climate scientists that much larger emission reductions are 

needed from fossil fuel-fired EGUs to address climate change, 

Deleted: .
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the EPA looked at additional measures to reduce emission rates. 

This reflects our conclusion that, given the availability of 

other measures capable of much greater emission reductions, and 

that possibility that in isolation more efficient plants could 

dispatch more and increase overall emissions, the emission 

reductions limited to this set of heat rate improvement measures 

would not meet one of the considerations critical to the BSER 

determination –- the quantity of emissions reductions resulting 

from the application of these measures is too small for these 

measures to be the BSER by themselves for this source category. 

Specifically, as described in the proposal, the EPA also 

considered co-firing (including 100 percent conversion) with 

natural gas, a measure that presented itself in part because of 

the recent increase in availability and reduction in price of 

natural gas, and the industry’s consequent increase in reliance 

on natural gas.351 The EPA also considered implementation of 

carbon capture and storage (CCS).352 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 

 

351 The EPA further addressed co-firing in the NODA. 79 FR 64549-

51. 

352 CCS is also sometimes referred to as carbon capture and 

sequestration. 
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in the context of other GHG rules, that a segment of the source 

category may implement these measures, and that the resulting 

emission reductions could be potentially significant. 

However, these co-firing and CCS measures are more 

expensive than other available measures. 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.353 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 

 

353 Similarly, demand-side energy efficiency measures are lowcost measures. 
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in most cases than more aggressive emission rate reduction 

measures at the steam EGU. As a result, as a practical matter, 

were the EPA to include co-firing and CCS in the BSER and 

promulgate performance standards accordingly, few EGUs would 

likely comply with their emission standards through co-firing 

and CCS; rather, the EGUs would rely on the lower cost options 

of substituting lower- or zero-emitting generation or, as a 

related matter, reducing generation.354

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 

 

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

measures. 
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measures that are available to the utility power sector thanks 

specifically to the integrated nature of the electricity system, 

and that involve, in one form or another, replacement of higher 

emitting generation with lower- or zero-emitting generation. 

Although the presence of lower-cost options that achieve 

the emission reduction goals mean that the EPA is not 

identifying either natural gas co-firing or CCS at coal-fired 

steam EGUs, or heat rate improvements at other types of EGUs, as 

part of the BSER, those controls remain measures that some 

affected EGUs may be expected to implement and that as a result, 

will provide reductions that those affected EGUs may rely on to 

achieve their emission limits or may sell, through emissions 

trading, to other affected EGUs to achieve emission limits (to 

the extent permitted under the relevant section 111(d) plans). 

Another example of a non-BSER measure that an affected EGU in 

certain circumstances could choose to implement is the 

conversion of waste heat from electricity generation into useful 

thermal energy. The EPA further discusses the potential use of 

these non-BSER measures for compliance flexibility below. 

The EPA’s quantification of the CO2 emission reductions 

achievable through heat rate improvements as a component of the 

BSER (building block 1) is discussed in section V.C. of this 
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preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(2) Measures available because of the integrated 

electricity system. 

To determine the BSER that meets the expectations and 

requirements of the CAA, including the achievement of meaningful 

reductions of CO2, the EPA turned next to the set of measures 

that presented themselves as a result of the fact that the 

operations of individual affected EGUs are integrated with one 

another and with the overall electricity system. Those are the 

measures in the categories represented in the proposal by 

building blocks 2, 3, and 4. This section discusses the 

components of the BSER that relate to building blocks 2 and 3, 

which the EPA is finalizing as components of the BSER. This 

section also discusses the measures comprising the proposed 

building block 4, which the EPA is not including in the BSER in 

this final rule. 

It bears reiterating that the extent to which the 

operations of individual affected EGUs are integrated with one 

another and with the overall electricity system is a highly 

salient and unique attribute of this source category. Because of 

this integration, the individual sources in the source category 
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operate through a network that physically connects them to each 

other and to their customers, an interconnectedness that is 

essential to their operation under the status quo and by all 

indications is projected to be augmented further on a continual 

basis in the future to address fundamental objectives of 

reliability assurance and cost reduction. This physical 

interconnectedness exists to serve a set of interlocking regimes 

that, to a substantial extent, determine, if not dictate, any 

given EGU’s operations on a nearly moment-to-moment basis. In 

analyzing BSER from a source-category perspective, because the 

affected EGUs are connected to each other operationally, a 

combination of dispatching and investment in lower- and zeroemitting generation allows the replacement of higher-emitting 

generation with lower-emitting and zero-emitting generation 

(measures in building blocks 2 and 3), and thereby reduces 

emissions while continuing to serve load. 

 As noted above, substitution of higher-emitting generation 

for lower- or zero-emitting generation may include reduced 

generation, depending on the specific action taken by the 

individual EGU. Likewise, when incorporated into standards of 

performance, emissions trading or other multi-unit compliance 

mechanisms may be readily used for implementing these building 
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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 coal-fired steam EGUs, 

which account for most generation from steam EGUs –- this 

generation shift reduces CO2 emissions. We also noted that 

because NGCC units can generate as much as 46 percent more 

electricity from a given quantity of natural gas than a steam 

unit can, generation shifting from coal-fired steam EGUs to 

existing NGCC units is a more cost-effective strategy for 

reducing CO2 emissions from the source category than converting 

coal-fired steam EGUs to combust natural gas or co-firing coal 

and natural gas in steam EGUs. We proposed to find that shifting 

generation consistent with a 70 percent target utilization rate 
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(based on nameplate capacity) for NGCC units was feasible and 

should be a component of the BSER. 

As described in section V.D. below, analysis reflecting 

consideration of the many comments we received on this issue 

supports the inclusion of generation shifting from higheremitting to lower-emitting EGUs as a component of the BSER. 

Shifting of generation among EGUs is an everyday occurrence 

within the integrated operations of the utility power sector 

that is used to ensure that electricity is provided to meet 

customer demands in the most economic manner consistent with 

system constraints. Generation shifting to lower-emitting units 

has been recognized as an approach for reducing emissions in 

other EPA rules such as CSAPR. 

The EPA’s analysis continues to show that the magnitude of 

emission reductions included in the proposed rule from 

generation shifting is achievable. Some commenters stated that 

summer capacity ratings are a more appropriate basis upon which 

to compute a target utilization than nameplate capacity ratings 

used at proposal. We agree, and accordingly, using the same data 

on historical generation as at proposal, we have reanalyzed 

feasible NGCC utilization levels expressed in terms of summer 
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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 of lower- or zero-CO2 generation that could 

replace higher-CO2 generation from affected EGUs. 

(i) Increased generation from new RE generating capacity. 

The EPA’s survey of trends and actions already being taken 

in the utility power sector indicated that RE generating 

capacity and generation have grown rapidly in recent years, in 
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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 

the preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(ii) Increased and preserved generation from nuclear 

generating capacity. 
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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 

difficult to ascertain a trend of increasing nuclear generation 

in the industry. These differences create greater uncertainty 
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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. 

(iii) Generation from new NGCC units. 

 New NGCC units –- that is, units that had not commenced 

construction as of January 8, 2014, the date of publication of 

the proposed CO2 standards of performance for new EGUs under 

section 111(b) –- are not subject to the standards of 

performance that will be established for existing sources under 
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section 111(d) plans based on the BSER determined in this final 

rule. In the June 2014 proposed emission guidelines for existing 

EGUs, the EPA solicited comment on whether to include this 

measure in the BSER. Commenters raised numerous concerns, and 

after consideration of the comments, we are not including 

replacement of generation from affected EGUs through the 

construction of new NGCC capacity in the BSER. Because we are 

not including new NGCC in BSER, it is not necessary to address 

each of the commenter’s concerns. In this section, we primarily 

discuss two reasons for our approach, and we then list, but do 

not further address, additional concerns raised by commenters. 

 The EPA did not include reduced generation from affected 

EGUs achieved through construction and operation of new NGCC 

capacity in the proposed BSER in part because we expected that 

the CO2 emission reductions achieved through such actions would, 

on average, be more costly than CO2 emission reductions achieved 

through the proposed BSER measures. In particular, we observed 

that these emission reductions would be more costly than the 

reductions achievable through increased generation from existing 

NGCC capacity under building block 2. The greater costs would 

arise from two factors: first, capital costs incurred to build 

the new NGCC capacity –- which of course would not be necessary 

Deleted: agree with these commenters

Deleted: their
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with respect to existing NGCC capacity –- and second, increases 

in the price of natural gas that would be expected to occur with 

additional usage of natural gas beyond the amounts used to 

increase generation from existing NGCC capacity. Although 

commenters expressed a range of views on whether replacement of 

generation from affected EGUs through generation from new NGCC 

capacity should be included in BSER, after consideration of 

comment we continue to view our cost concerns related to these 

two factors as valid and salient. 

 In addition, we note that unlike emission reductions 

achieved through the use of any of the building blocks, emission 

reductions achieved through the use of new NGCC capacity require 

the construction of additional CO2-emitting generating capacity, 

a consequence that is inconsistent with the long-term need to 

continue reducing CO2 emissions beyond the reductions that will 

be achieved through this rule. For both these reasons –- greater 

cost than the emission reductions achievable through the 

building blocks and the long-term policy concerns about 

construction of additional CO2-emitting generating capacity –- we 

are not including replacement of generation from affected EGUs 

through the construction and operation of new NGCC capacity in 

the final BSER. 
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 Commenters raised additional concerns. First, commenters 

expressed concern with the interrelation of section 111(b) and 

section 111(d). New NGCC capacity is distinguished from the 

other non-BSER measures discussed above by the fact that its CO2

emissions would be subject to the CO2 standards for new EGUs 

being established under section 111(b). Section 111 creates an 

express distinction between the sources subject to section 

111(b) and the sources subject to section 111(d), and commenters 

expressed concern that to allow section 111(b) sources to play a 

direct role in setting the BSER under section 111(d) would be 

inconsistent with congressional intent to treat the two sets of 

sources separately. Section VIII of this preamble includes a 

discussion of ways to address new NGCC capacity in the context 

of different types of section 111(d) plans. 

Commenters also expressed concern with the potential 

incentives created by including new NGCC capacity in the BSER. 

Some commenters suggested that including new NGCC capacity in 

the BSER would distort market incentives to build new NGCC 

units, particularly if new units were allowed to generate 

emission rate credits (ERCs) that could be sold to affected 

EGUs. These commenters suggested that the additional incentive 

for new NGCC units could make existing NGCC units less 
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competitive. Other commenters suggested that including new NGCC 

capacity in the BSER would promote generation from new CO2-

emitting units at the expense of new zero-emitting units, 

increasing overall emissions within a state. This effect would 

be exacerbated if state plans allowed new NGCC units to be 

treated as “zero-emitting” for purposes of compliance –- as 

suggested by other commenters. 

 In addition, commenters expressed concern that the EPA’s 

inclusion of new NGCC capacity in setting the BSER could 

negatively impact ratepayers over the long-term by sending the 

wrong signal to industry and resulting in stranded assets if, in 

the future, carbon emissions become more expensive or the EPA 

proposes to incorporate sources built under the forthcoming 

section 111(b) standard into the section 111(d) program. 

 Commenters also expressed concern that including generation 

from new NGCC units in setting the BSER could create 

unreasonable uncertainty in the standard, given limitations on 

the ability to accurately project new NGCC builds; could create 

undue pressure on natural gas prices; and could create unfair 

disparities in the compliance opportunities afforded different 

states. 
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 (c) Increasing demand-side energy efficiency to avoid 

generation and emissions from fossil fuel-fired EGUs. 

The final category of approaches for reducing generation 

and CO2 emissions from affected EGUs that the EPA considered in 

the proposal involves increasing demand-side energy efficiency. 

When demand-side energy efficiency is increased, energy 

consumers need less electricity in order to provide the same 

level of electricity-dependent services – e.g., heating, 

cooling, lighting, and use of motors and electronic devices. 

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 
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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 

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 provides greater assurance of the 

achievability of the BSER for the source category and for 
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individual sources. We believe this approach is permissible 

under the CAA. 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 three 

Interconnections355 –- 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 

 

355 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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guidelines include mechanisms for implementing standards of 

performance that incorporate interstate trading, as discussed in 

section VIII. (In addition, as further discussed below, the rule 

also permits section 111(d) plans to allow the use of non-BSER 

measures for compliance in certain circumstances, increasing 

both compliance flexibility and the assurance that the emission 

limitations reflecting application of the BSER are achievable.) 

Further, the sets of measures in each of these individual 

building blocks, in the stringency assigned in this rule, meet 

the criteria for the BSER. That is, they each achieve the 

appropriate level of reductions, are of reasonable cost, do not 

impose energy penalties on the affected EGUs and do not result 

in non-air quality pollutants, and have acceptable cost and 

energy implications 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 
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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 building blocks 2 and 3 also 

meet the criteria for the BSER in combination with one another 

and with building block 1, as described below. 

e. 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. 

As discussed in section V.C., the record makes clear that EGUs 

can make, and have made, such improvements to a greater or 

lesser degree, resulting in reductions in CO2 emissions. 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 
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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, 

there are several ways that affected EGUs can access the 

measures in building blocks 2 and 3, thanks to the integrated 

nature of the electricity system, coupled with the system’s high 

degree of planning and reliability mechanisms. The affected EGUs 

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

lead to reductions in higher-emitting generation at other units 

in the integrated system; (b) reduce their generation, 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 Formatted: Highlight
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the measures in the building blocks elsewhere in the integrated 

system; or (c) both invest in the measures in the building 

blocks and reduce their own generation, effectively replacing 

their generation with cleaner generation. The availability of 

these options is further enhanced where the individual EGU is 

operating under a standard of performance that incorporates 

emissions trading. 

(a) Investment in measures in building blocks 2 and 3. 

An affected EGU may take the following actions to invest in 

the measures in building blocks 2 and 3: For building block 2, 

the owner/operator of a steam EGU may increase generation at an 

existing NGCC unit it already owns, or one that it purchases or 

invests in. In addition, the owner/operator may, through a 

bilateral transaction with an existing NGCC unit, pay the unit 

to increase generation, and 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 

Formatted: Highlight
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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 specify the 

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.356 

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, a source could achieve a standard of performance 

identical to the applicable CO2 emission performance rate in the 

 

356 Criteria for issuance of valid emission rate credits and for 

tracking credits after issuance are discussed in section VIII 

below. 
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EPA emission guidelines, or the mass limit equivalent, 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 

such a program.357 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. 

 

357 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. 
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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. 

Such markets have developed for other instruments used for 

emissions trading purposes. 

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

plans mechanisms or standards of performance involving 

instruments such as emission rate credits (ERCs), there should 

be an ample 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 
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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 

latitude the final guidelines provide for states to set 

standards of performance incorporating emissions trading that 

includes the use of multi-state trading among affected sources 

or other multi-unit compliance approaches among sources in 

different Interconnections, all sources can take advantage of 

the headroom available in other Interconnections. As a result, 

significant amounts of existing NGCC capacity and potential for 

renewable energy remain available to serve as the basis for 

issuance of ERCs for all affected EGUs in both source 

subcategories to rely on to achieve their emission limits. 

Because we recognize the ready availability to states of 
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standards of performance that incorporate emissions trading –- 

and because such standards can easily encompass interstate 

trading -- this rule includes by express design a variety of 

options that states and utilities can select to pursue 

interstate compliance regimes that mirror the interconnected 

operation of the electricity system. As a result, the EPA 

believes that it is reasonable to anticipate that a virtually 

nationwide emission trading market for compliance will emerge, 

and that ERCs will be effectively available to any source 

wherever located, as long as its state plan authorizes either 

emissions trading among affected sources or the purchase and use 

of ERCs in meeting the standard of performance the state 

establishes.358

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 

 

358 There is a theoretical possibility – which we view as 

extremely unlikely – that the affected EGUs in a given state 

that has chosen to pursue a rate-based approach could have 

insufficient access to ERCs because of the choices of all or 

most other states to pursue mass-based approaches. In such a 

situation, it might be appropriate to allow the affected EGUs in 

that state to assume for purposes of demonstrating compliance 

with their standards of performance that the generation 

replacing any reductions in generation at those affected EGUs 

that was not paired with quantified ERCs came from existing NGCC 

units in other states. 
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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 

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 
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restriction on the amount of hours that it generates. In 

addition or alternatively, it may represent the cost of 

additional emission credits or allowances that would be required 

due to incremental generation as an additional variable cost 

that increases the total variable cost considered when dispatch 

decisions are made for the unit. 

Because of the integrated nature of the electricity system, 

combined with the system’s high degree of planning and 

reliability safeguards, as well as the long planning horizon 

afforded by this rule, individual affected EGUs can in aggregate 

achieve the requisite level of reductions in generation adequate 

to achieve emission limits reflecting the BSER.359 Individual 

affected steam EGUs can reduce their generation in the amounts 

of building blocks 2 and 3, while individual affected NGCC units 

can reduce their generation in the amount of building block 3. 

With emission limits for the source category as a whole in 

place, the resulting reduction in supply of higher-emitting 

generation will incentivize additional utilization of existing 

NGCC capacity, and the resulting reduction in overall fossil 

 

359 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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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.

(c) Emissions trading. 

As described above, viewed from the source-category 

perspective, it is reasonable for our analysis of the BSER to 

include an element of source-category-wide multi-unit compliance 

which could be implemented via a state-set standard of 

performance incorporating emissions trading, under which EGUs 

could engage in trading of rate-based emission credits or massbased emission allowances. By the same token, viewed from the 

individual-source perspective, consideration of the ready 

availability to states of the opportunity to establish standards 

of performance that incorporate emissions trading is integral to 

our analysis, and our assessment of the actions available to 

individual sources for achieving standards of performance 

reflecting the BSER therefore include 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 
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allowances would have to be authorized, of course, in the 

purchasing sources’ states’ section 111(d) plans and would have 

to meet conditions set out for such approaches in section VIII 

below. The role of emissions trading in the BSER analysis is 

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

 (d) Other multi-unit compliance approaches. 

The measures included in the BSER are also available 

through standards of performance and state plans that operate 

without emissions trading involving tradable instruments (e.g., 

rate-based emission credits or mass-based emission allowances) 

but include other multi-unit compliance approaches that reflect 

the global nature of the CO2 pollutant and the interconnected 

nature of the electricity system. 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 highercost emission-reduction opportunities. Thus, like emissions 

trading, these approaches effectively make it possible for 

affected EGUs to invest in emission reduction measures that are 

Commented [A11]: This discussion seems helpful--It would be 

good to better understand why this discussion was deleted 
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physically implemented at other locations, consistent with 

longstanding practice in the interconnected electricity system. 

For units subject to rate-based performance standards, 

multi-unit compliance approaches other than emissions trading 

approaches would generally be “averaging” approaches where 

multiple units would combine their monitored emissions and 

generation (as well as any authorized emission rate credits 

representing the emissions-reducing benefits of investments in 

specific emissions-reducing activities) in order to compute a 

combined emission rate that would, in turn, be compared to a 

combined rate-based performance standard. For units subject to 

mass-based performance standards, such approaches would 

generally be “aggregation” approaches where multiple units would 

combine their monitored emissions in order to compute a combined 

total mass of emissions that would, in turn, be compared to a 

combined mass-based performance standard.360 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. 

 

360 Approaches that aggregate emissions of multiple units at a 

single facility are commonly known as “bubbling” approaches. 
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f. The role of emission trading. In making its BSER 

determination here, the EPA examined a number of technologies 

and emissions reduction measures that result in lower levels of 

CO2 emissions and evaluated each one on the basis of the several 

criteria on which the EPA relies in determining the BSER. In 

contrast to section 111(b), however, section 111(d)(1) obliges 

the states, not the EPA, to set standards of performance for the 

affected sources in order to implement the BSER. Accordingly, 

with respect to each measure or control strategy under 

consideration, the EPA also evaluated whether or not the states 

could establish standards of performance for affected EGUs that 

would allow those sources to adopt the measure in question. In 

this case, the EPA identified a host of factors that persuaded 

us that a state could establish a standard of performance that 

incorporated emissions trading. These wide-ranging factors 

include (i) the global nature of the air pollutant in question – 

i.e., CO2; (ii) the transactional nature of the industry; (iii) 

the interconnected functioning of the industry and the 

coordination of generation resources at the level of the 

regional grid; (iv) the extensive experience that states – and 

EGUs – already have with emissions trading; and (v) material in 
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the record suggesting interest on the part of affected EGUs and 

states in using emissions trading in meeting their obligations. 

The states’ and EGUs’ interest in emissions trading is 

rooted in the well-recognized benefits that trading provides. 

The experience of multiple trading programs over many years has 

shown that some units can achieve emissions reductions at lower 

cost than others, and a system that allows for those lower-cost 

reductions to be maximized is more cost-effective overall to the 

industry and to society. Trading provides an affected EGU other 

options besides direct implementation of emission reduction 

measures in its own facility or an affiliated facility when 

lower-cost emission reduction opportunities exist elsewhere. 

Specifically, the affected EGU can cross-invest, that is, invest 

in actions at facilities owned by others, in exchange for ratebased emission credits or mass-based emission allowances. 

Through cross-investment, trading allows each affected EGU to 

access the control measures that other affected EGUs decide to 

implement, which in this case include all the building blocks as 

well as other measures. 

Accordingly, our analysis of the measures under 

consideration in our BSER determination reflected the wellfounded conclusion that it is reasonable for states to 
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incorporate emissions trading in the standards of performance 

they establish for affected EGUs and that many, if not all, 

would do so. 

Whether viewed through the source category or individual 

source perspective, emissions trading is thus an integral part 

of our BSER analysis. Again, we concluded that this is 

reasonable given the global nature of the pollutant, the 

transactional and interconnected nature of this industry, and 

the long history and numerous examples demonstrating that, in 

this sector, trading is integral to how regulators have 

established, and sources have complied with, environmental and 

similar obligations (such as renewable energy standards) when it 

was appropriate to do so given the program objective. The 

reasonableness is further demonstrated by the numerous comments 

from industry, states, and other stakeholders in this rulemaking 

that supported allowing states to adopt trading programs to 

comply with section 111(d) and encouraged EPA to facilitate 

trading across state lines through the use of trading-ready 

state plans. The EPA’s reliance on trading in its BSER 

determination does not mean, however, that states are required 

to establish trading programs (just as states are not required 

to implement the building blocks that comprise BSER). Nor does 
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it mean that trading is the only transactional approach that we 

could have considered in setting the BSER or that states could 

use to effectuate the building blocks were they to decide that 

they did not want to take on the responsibility of running a 

trading program. Rather, it is simply a recognition of the 

nature of this industry and the long history of trading as an 

important regulatory tool in establishing regulatory regimes for 

this industry and its reasonable availability to states in 

establishing standards of performance. 

As an initial matter, trading is permissible for these 

emission guidelines because CO2 is a global pollutant; the 

location of its emission does not affect the location of the 

environmental harm it causes. For CO2, it is the total amount of 

emissions from the source category that matters, not the 

specific emissions from any one EGU. The fact that trading 

allows sources to shift emissions from one location to another 

does not impede achievement of the environmental goal of 

reducing CO2 pollution. In its character as a pollutant whose 

impacts extend beyond local areas, CO2 pollution resembles to 

some extent the regional SO2 pollution that Congress chose to 

address with the emissions trading program enacted in Title IV 

of the 1990 CAA Amendments. The argument in support of trading 
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approaches is even stronger for CO2 pollution, whose adverse 

effects are global rather than merely regional like the SO2

emissions contributing to acid precipitation. 

Further, as discussed elsewhere in the preamble, the 

utility power sector – and the affected EGUs and other 

generation assets that it encompasses – has a long history of 

working on a coordinated basis to meet operating and 

environmental objectives, necessitated and facilitated by the 

unique interconnectedness of the sector. That history includes 

joint dispatch for economic and reliability purposes, both 

within large utility systems and in multi-utility power pools 

that have evolved into RTOs; joint power plant ownership 

arrangements; and long-term and short-term bilateral power 

purchase arrangements. More recently, the sector’s history also 

includes emissions trading programs designed by Congress, the 

EPA, and the states to address regional environmental problems 

and, most recently, climate change. Examples of such programs 

are noted below. 

Essentially, trading does nothing more than commoditize 

compliance, with the following two important results emerging 

from that: it reduces the overall costs of controls and spreads 

those costs among the entire category of regulated entities 
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while providing a greater range of options for sources that may 

not want to make on-site investments for controlling their 

emissions and may prefer to make the same investment, via the 

purchase of the tradable compliance instrument, at another 

generating source. Building blocks 2 and 3 entail affected EGUs 

investing in increased generation from existing NGCC units and 

renewable energy. The affected EGUs could do so in any number of 

ways, including acquiring ownership interests in existing NGCC 

or renewable energy facilities or entering into bilateral 

transactions with the owners of existing NGCC facilities or 

renewable energy sources. As discussed elsewhere, it is 

reasonable to expect that these actions can develop into 

discrete, tradable commodities (e.g., an emission rate credit, 

or ERC) and that liquid markets will develop, which would reduce 

transaction costs and allow an affected EGU to comply with its 

emission limits by purchasing discrete units in amounts tailored 

closely to its compliance needs. The existence of such tradable 

commodities also incentivizes over-compliance by affected EGUs, 

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

allowances to other affected EGUs. Moreover, as noted elsewhere, 

the opportunity to trade is consistent with the EPA’s regional 

approach for the building blocks. 
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By the same token, the opportunity to trade incentivizes 

affected EGUs to over-comply with building block 1. Thus, the 

opportunity to trade supports the EPA’s assumptions about what 

an average affected EGU can achieve with regards to heat rate 

improvement even if each and every affected EGU cannot achieve 

that level of improvement. In addition, trading incentivizes 

affected EGUs to consider low-cost, non-BSER methods to reduce 

emissions as well, and as discussed below, there are numerous 

non-BSER methods, ranging from implementation of demand-side 

energy efficiency programs to natural gas co-firing. 

Trading has become an important mechanism for achieving 

environmental goals in the electricity sector in part because 

trading allows environmental regulators to set an environmental 

goal while preserving the ability of the operators of the 

affected EGUs to decide the best way to meet it taking account 

of the full range of considerations that govern their overall 

operations. For example, commenters were concerned that because 

of building block 2, the emission guidelines would require state 

environmental regulators to make dispatch decisions for the 

electricity markets, a role that state environmental regulators 

do not currently play. Although building block 2 entails 

substituting existing NGCC generation for steam generation, 
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implementing the emission limits that are based in part on 

building block 2 through a trading program provides the 

individual affected EGUs with a great deal of control over their 

own generation while the industry as a whole achieves the 

environmental goals. For example, individual steam generators 

have the option of maintaining their generation as long as they 

purchase additional ERCs. Moreover, trading provides a way for 

states to set standards of performance that realize the required 

emissions reduction without requiring any form of “environmental 

dispatch” because, as many existing trading programs have shown, 

monetization of the environmental constraint is consistent with 

a least-cost dispatch system. Trading also supports the EPA’s 

approach to the “remaining useful life” provision in section 

111(d)(1) because with trading, an affected source with a 

limited remaining useful life can avoid the need to implement 

long-term emission reduction measures and can instead purchase 

ERCs or other tradable instruments, such as mass-based 

allowances, thereby allowing the state to meet the requirements 

of this rule. 

The EPA’s job in issuing these emission guidelines is to 

determine the BSER that has been adequately demonstrated and to 

set emission limitations that are achievable through the 
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application of the BSER and implementable through standards of 

performance established by the states. The three building blocks 

are the EPA’s determination of what technology is adequately 

demonstrated. We also consider trading an integral part of the 

BSER analysis because, in addition to being available to states 

for incorporation in the standards of performance they set for 

affected EGUs, trading has been adequately demonstrated for this 

industry in circumstances where systemic rather than unit-level 

reductions are central. Congress, the EPA, and state regulators 

have established successful environmental programs for this 

industry that allow trading of environmental (or similar) 

attributes, and trading has been widely used by the industry to 

comply with these programs. Examples include the CAA Title IV 

Acid Rain Program, the NOX SIP Call (currently referred to as the 

NOX Budget Trading Program), the Clean Air Interstate Rule 

(CAIR), the Cross-State Air Pollution Rule (CSAPR), the Regional 

Haze trading programs, the Clean Air Mercury Rule,361 RGGI, the 

 

361 Although the CAMR trading program never took effect because 

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

nationwide trading program that the EPA adopted under CAA 

section 111(d). Some states declined to allow their sources to 

participate in the trading program on the grounds that 

nationwide trading was not appropriate for the air pollutant at 

issue, mercury, a hazardous air pollutant that caused adverse 

local impacts. 
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trading program established by California AB32, and the South 

Coast Air Quality Management District RECLAIM program. We 

describe these programs in the background section of this 

preamble. In addition, we note in the Legal Memorandum 

accompanying this preamble that Congress, in enacting the Title 

IV acid rain trading program, and the EPA, in promulgating the 

regulatory trading programs listed, recognized both the 

suitability of trading for the EGU industry and the benefits of 

trading in reducing costs, spreading costs to affected EGUs 

throughout the sector, and facilitating the ability of affected 

EGUs to comply with their emission limits. In addition, as we 

discuss in section V.E. of this preamble, many states have 

adopted renewable energy standards that promote renewable energy 

through the trading of renewable energy credits (RECs). 

Based on this history, it is reasonable for the EPA to 

determine that states can establish standards of performance 

that incorporate trading and, as a result, for purpose of making 

a BSER determination here to evaluate prospective emissions 

control measures in light of the availability of trading. 

Trading is a regulatory mechanism that works well for this 

industry. The environmental attributes in the preceding programs 

(representing emissions of air pollutants) are identical to or 
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similar in nature to the environmental attribute here (CO2

emissions). The markets for RECs show that robust markets for 

renewable energy, in particular, already exist. 

Given the benefits of trading and the background of multiunit coordination grounded in the nature of the utility power 

sector, it is natural for sources and states to look for 

opportunities to apply similar coordination to a regional 

problem such as reduction of CO2 emissions from the sector. The 

EPA heard this interest expressed during the outreach process 

for this rulemaking and saw it reflected in comments on the 

proposal. Emissions trading was prominent in these expressions 

of interest: while the proposal allowed trading and encouraged 

the development of multi-state plans which would allow the 

benefits of trading to extend over larger regions, we heard that 

interest was even greater in “trading-ready” plans that would 

use trading mechanisms and market-based coordination, rather 

than state-to-state coordination, as the primary means of 

facilitating multi-unit approaches to compliance. The general 

industry and state preference for multi-unit compliance 

approaches makes great sense in the context of the industry and 

this pollutant, as does the specific preference for tradingready section 111(d) plans, and we have made efforts in the 
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final rule to accommodate trading-ready plans as described in 

section VIII. 

g. Measures that reduce CO2 emissions or CO2 emission rates but 

are not included in the BSER. There are numerous other measures 

that are available to at least some affected EGUs to help assure 

that they can achieve their emission limits, even though the EPA 

is not identifying these measures as part of the BSER. These 

measures include demand-side energy efficiency implementable by 

affected EGUs; new or up-rated nuclear generation; renewable 

measures other than those that are part of building block 3, 

including distributed generation solar power and off-shore wind; 

combined heat and power and waste heat power; and transmission 

and distribution improvements. In addition, a state may 

implement measures that yield emission reductions for use in 

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. 
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h. Ability of EGUs to implement the BSER. The EPA’s analysis, 

based in part on observed decades-long behavior of EGUs, shows 

that all types and sizes of affected EGUs in all locations are 

able to undertake the actions described as the BSER, including 

investor-owned utilities, merchant generators, rural 

cooperatives, municipally-owned utilities, and federal 

utilities. Some may need to focus more on certain measures; for 

example, an owner of a small generation portfolio consisting of 

a single coal-fired steam EGU may need to rely more multi-unit 

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. Since states 

can reasonably be expected to establish standards of performance 

incorporating emissions trading, affected EGUs may rely on 

emissions trading or other multi-unit compliance approaches 

authorized under their states’ section 111(d) plans to, in 

effect, invest in building block measures that are physically 

implemented at other locations. As discussed above, the EPA’s 
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quantification of the CO2 emission performance rates in a manner 

that provides headroom within the BSER also contributes to the 

ability of all affected EGUs to implement the BSER and achieve 

emissions limitations consistent with those performance rates. 

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

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

in the emission guidelines that we are promulgating with this 

rule, we are treating steam EGUs and combustion turbines as 

separate subcategories. We are determining the BSER for steam 

EGUs and the BSER for combustion turbines, and applying the BSER 

to each subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. As we discuss below, 

this approach is fully consistent with the provisions of section 

111(d), which simply require the EPA to determine the BSER, do 

not prescribe the method for doing so, and are silent as to 

subcategorization. This approach is also fully consistent with 

other provisions in section 111, which require the EPA first to 

list source categories that may reasonably be expected to 

endanger public health or welfare and then to regulate new 

sources within each such source category, and which grant the 
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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 

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 
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affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates and can do so at a reasonable cost using the 

approaches we have identified as the BSER as well as other 

available measures. 

 Of course, a state retains great flexibility in assigning 

standards of performance to its affected EGUs and can impose 

different emission reduction obligations on its sources, as long 

as the overall level of emission limitation is at least as 

stringent as the emission guidelines, as discussed below. 

3. Changes from proposal 

 For the BSER determined in this final rule, based on 

consideration of comments, the EPA has adopted certain 

modifications 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 modifications yield 

emission reductions requirements that commence more gradually 

than the proposed goals but are projected to produce slightly 
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greater emission reductions overall by 2030.362 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.363 Informed by comments, the EPA has clarified some of 

these interpretations, and has developed a more refined 

understanding of how some of these interpretations should be 

applied. The clarified and more refined interpretations replace 

the proposed interpretations, as indicated in section V.A.1. and 

the Legal Memorandum for the CPP Final Rule available in the 

docket, as well as in the final rule for new sources promulgated 

concurrently with this final rule for existing sources. 

 Two of these points merit mention here. First, the EPA is 

clarifying in this rule that the interpretation of “system of 

 

362 For the proposed rule, the EPA projected total CO2 emission 

reductions from 2005 levels of 29% in 2025 and 30% in 2030. For 

the final rule, the EPA projects total CO2 emissions reductions 

from 2005 levels of 28% in 2025 and 32% in 2030. See Regulatory 

Impact Analysis for the CPP Proposed Rule, Table 3-6, and 

Regulatory Impact Analysis for the CPP Final Rule, Table 3-6, 

available in the docket. 

363 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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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 be accomplished only through government 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 

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 
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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. In this final rule, we are obviating those 

concerns by assessing the emission reduction opportunities at an 

appropriate regional scale and formulating nationally uniform 

emissions standards. National uniformity is consistent with 

prior section 111 rulemaking. The methodological refinements 

related to regional assessment of 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 

Deleted: ).

Commented [A12]: Note that as states will presumably not all 

adopt the 2 rate approach, this effect is only obviated in the context 

of the BSER and not in implementation 
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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 

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 
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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.364 Further details 

regarding the final rule’s quantification of RE generation are 

provided in section V.E. below. 

c. Exclusion from the BSER of emission reductions from use of 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 

 

364 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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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. While we recognize the important 

role nuclear power plants have to play in providing carbon-free 

generation in an all-of-the-above energy system, for this final 

rule, the BSER does not include either of the components related 

to nuclear generation. 

 The EPA received numerous comments on the proposed BSER 

components related to nuclear power. With respect to generation 

from 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 

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 
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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 in much larger losses of generation 

in those particular states. 

 Upon consideration of comments and the accompanying data, 

the EPA has determined that the BSER should not include either 

of the components related to nuclear generation from the 

proposal. With respect to nuclear units under construction, 

although we believe that other refinements to this final rule 

would address commenters’ concerns that 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 
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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. 

 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 and use of credits, as discussed in section V.A.6.b., 

and would help sources meet mass-based standards of performance 
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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.365

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. 

Building block 4 caused generated considerable controversy 

among commenters. While many commenters emphasized the costeffectiveness of demand-side energy efficiency measures, others 

expressed significant concerns. 

 

365 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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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 highly substitutable product) with fewer 

CO2 emissions, whereas the demand-side energy efficiency measures 

in building block 4 do not provide the same amount of generation 

through cleaner processes, but instead bring about reductions in 

demand for electricity, which avoids the need for corresponding 

amounts of electricity generation. 
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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 

producers, who comprise some 35-40 percent of the industry, but 

do not have a direct business relationship with end-users –- 

could do so. 
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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 

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 
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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.366 

 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. Compared to the proposal’s more state-focused 

quantification approach, a regionalized approach better reflects 

the interconnected system within which affected EGUs actually 

carry out planning and operations in order to meet electricity 

demand. Because it better reflects how the industry works, a 

regionalized approach also better represents the full scope of 

emission reduction opportunities available to individual 

affected EGUs. Further, use of a broad regionalized approach, as 

opposed to a state-focused approach, is more consistent with the 

global nature of CO2 as a pollutant. 

 

366 For building block 4, potential demand-side EE was first 

quantified on a state-specific basis but the emission reduction 

consequences for electricity-importing states were then adjusted 

downward in the goal setting process in order to account for 

regional effects; we solicited comment on making parallel upward 

adjustments to the goals for net electricity-exporting states to 

account for the regional effects more completely. 
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 Characterizing and quantifying the measures included in the 

BSER on a regional basis is also appropriate because states can 

establish standards of performance that incorporate emissions 

trading, including trading between and among EGUs operating in 

different states, and thus provide EGUs the opportunity to 

trade. Emissions trading provides at least one mechanism by 

which owners of affected EGUs can access any of the building 

blocks at other location. With emissions trading, an affected 

EGU whose access to heat rate improvement opportunities, 

incremental generation from existing NGCC units, or generation 

from new renewable energy generating capacity is relatively 

favorable can overcomply with its own standard of performance 

and sell rate-based emission credits or mass-based emission 

allowances to other affected EGUs. Purchase of the credits or 

allowances by the other EGUs represents cross-investment in the 

emission reduction opportunities, and such cross-investment can 

be carried out on as wide a geographic scale as trading rules 

allow. 

 The regions we have determined to be appropriate for the 

regionalized approach in the final rule are the Eastern, 

Western, and Texas Interconnections, as we explain in more 

Formatted: Highlight
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detail below.367 Each of the building blocks is quantified and 

applied at the regional level, resulting in the computation for 

each region of a performance rate for steam EGUs and a 

performance rate for NGCC units. For each of the technology 

subcategories, we identify the most conservative –- that is 

least stringent –- of the three regional performance rates. 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 within and across the regions 

(although the actual state goals vary among states to reflect 

the differences in generation mix among states). 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. 

 

367 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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 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 

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 
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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 

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 
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RTO/ISOs, or large-utility dispatch across multiple balancing 

areas. As a result, the fact that much of the necessary 

coordination for the interconnections is performed regionally on 

a partially decentralized basis (at least in the case of the 

Eastern and Western Interconnections) or occurs through the 

operation of automated equipment and the physics of the grid 

does not render the subregions more relevant than the 

interconnections as the ultimate regions within which 

electricity supply and demand must balance. 

 Second, 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 
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being managed through interconnection-wide planning, 

coordination and operations, and will continue to be managed in 

that manner in the future with or without this rule. While 

electricity supply and demand must be balanced in real time in a 

manner that observes all security constraints at that point in 

time, and key aspects of that management are carried out at a 

subregional scale, the emissions standards established in this 

rule can be met over longer timeframes through processes managed 

at larger geographic scales, just as they are today. We believe 

this rule will reinforce these developments and help provide a 

secure basis for moving forward. If a local transmission 

constraint requires that for reliability reasons a higheremitting resource must operate during a certain period of time 

in preference to a lower-emitting resource that would otherwise 

be the more economic choice when all costs are considered, 

nothing in this rule prevents the higher-emitting source from 

being operated. If the same transmission constraint causes the 

same conditions to occur frequently, the extra cost associated 

with finding alternative ways to reduce emissions will provide 

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 
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reduce emissions, the rule allows parties to pursue those 

alternative emission reduction measures. Accommodation of 

intermittent constraints and evaluation of alternatives for 

relieving or working around them have been routine operating and 

planning practices within the utility power sector for many 

years; the rule will not change these basic economic practices 

that occur today. The 2022-29 schedule for the rule’s interim 

goals and the 2030 schedule for the rule’s final goals allow 

time for planning and investment comparable to the sector’s 

typical planning horizons. 

 Finally, the EPA also considered whether the smaller 

geographic scales on which affected 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, 
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RTOs regularly manage flows between RTOs, and EGUs near the 

boundaries of RTOs impact multiple subregions across the 

interconnections, so that any subregional boundaries that might 

be evaluated for potential relevance as trading region 

boundaries will change as conditions and EGU choices change, 

while interconnection boundaries will remain stable. In 

addition, the final rule permits trading of rate-based emission 

credits or mass-based emission allowances. Emission allowances 

and other commodities associated with electricity generation 

activities, such as 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 
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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. 

 Specifically, the final rule reflects a performance rate of 

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

a performance rate of 770 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 
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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 

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 CO2

emission performance rates 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 
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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 what is reasonably achievable 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 the standards would be 

achievable at reasonable cost and without adverse impacts on 

reliability, 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 Guam368 –- because affected EGUs 

 

368 The section 111(d) requirements do not currently apply to the 

other isolated U.S. territories –- the U.S. Virgin Islands, 
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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 CO2

Emission Performance Rate and Goal Computation TSD for the CPP 

Final Rule. 

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 

 

American Samoa, and the Northern Mariana Islands –- because no 

affected EGUs currently operate in these territories. 
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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 

and will, in combination with the underlying emission reduction 

glide path and the ability of states to average across the 

compliance period, provide ample time for planning and 

investment activities that will be necessary to enable

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 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 

Deleted: given

Deleted: nature and magnitude of

Deleted: begin
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preamble sections for each building block (sections V.C., V.D., 

and V.E.) and emission performance rate computation (section VI) 

and in the GHG Mitigation Measures TSD for the CPP Final Rule 

and the CO2 Emission Performance Rate and Goal Computation TSD 

for the CPP Final Rule. As previously noted, viewed in terms of 

projected nationwide emission reductions, these refinements 

generally tend to make the interim goals somewhat less stringent 

than at proposal and the 2030 goals somewhat more stringent than 

at proposal. In addition to the changes described above, the 

refinements include the following: 

 Use of regional rates ranging from 2.1 percent to 4.3 

percent (rather than 6 percent) as the average heat rate 

improvement opportunity achievable by steam units under 

building block 1. 

 Use of 75 percent of summer capacity (rather than 70 

percent of nameplate capacity) as the target capacity 

factor for existing NGCC units under building block 2. 

 Use of updated information from the National Renewable 

Energy Laboratory (NREL) on renewable energy costs and 

potential, and revision of the list of quantified RE 

technologies to exclude landfill gas under building block 

3. 

Commented [A13]: I believe close to 30 states will have weaker 

2030 targets under the current numbers (considering removal of 

under constructed nuclear from baseline rates, the total would be 

29), so this text should likely be adjusted 
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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 can be 

implemented through standards of performance set by the states 

and includes a set of actions that individual sources can use to 

achieve the emission limitations reflecting the BSER. These 

actions and mechanisms, which include reduced generation and 

emissions trading or other multi-unit compliance approaches 

where the state-set standards of performance incorporate trading 

or the state plans permit multi-unit 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 

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 
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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 (or in some individual 

years of the interim goal period for NGCC units, the Texas 

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 costs based on the 
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application of the BSER to that state or territory are less 

stringent than the nationwide rates, the state- or territoryspecific performance rates are used instead.) This approach is 

consistent with the approach we have taken in other NSPS 

rulemakings, where the degree of emission limitation achievable 

through the application of the BSER for each subcategory of 

affected sources generally has been determined not on the basis 

of what is achievable by the sources that can reduce emissions 

most easily, but instead on the basis of what is reasonably 

achievable through the application of the BSER. 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 authorizing states to 

establish standards of performance that incorporate trading 

without geographic restrictions, the opportunity of affected 

EGUs to engage in emissions trading or other multi-unit 

compliance approaches, to the extent allowed under the relevant 

section 111(d) plans, ensures the availability of additional, 
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lower-cost emission reduction opportunities in other regions 

that will also promote compliance flexibility and reduces 

compliance costs. 

 As discussed in section XI of the preamble and the 

Regulatory Impact Analysis, application of the BSER determined 

as summarized above is projected to result in substantial and 

meaningful reductions of CO2 emissions. 

 Briefly, the elements of the BSER are: 

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 
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BSER with respect to coal-fired steam EGUs369 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 

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 

 

369 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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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 

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 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 
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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, thereby allowing 

building block 1 to be considered an appropriate part of the 

BSER for CO2 emissions at affected EGUs as long as the building 

block is applied in combination with other building blocks. 

b. Building block 2. Building block 2 –- 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, 
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are of reasonable cost, and perform well with respect to other 

factors relevant to a determination of the “best system of 

emission reduction ... adequately demonstrated.” Building block 

2 is a “system of emission reduction” for steam EGUs because 

incremental generation from existing NGCC units will result in 

reduced generation and emissions from steam EGUs, and owners of 

steam EGUs can, and many do, invest in incremental generation 

from NGCC units through a variety of possible mechanisms. A 

steam EGU investing in incremental generation from NGCC units 

may choose to reduce its own generation or may maintain its 

generation level and choose to allow the reduction in generation 

to occur at other steam EGUs through the coordinated planning 

and operation of the interconnected electricity system. An 

affected EGU may also invest in emission reductions from 

building block 2 through the mechanism of engaging in emissions 

trading where it is operating under a standard of performance 

that incorporates trading. 

 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable at high-emitting EGUs through generation shifts to 

lower-emitting affected EGUs are discussed in Section V.D. 

below. We consider generation shifts among the large number of 
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diverse EGUs that are linked to one another and to customers by 

extensive regional transmission grids to be a routine and wellestablished operating practice within the industry that is used 

to facilitate the achievement of a wide variety of objectives, 

including environmental objectives, while meeting the demand for 

electricity services. In the interconnected and integrated 

electricity industry, fossil fuel-fired steam EGUs are able to 

reduce their generation and NGCC units are able to increase 

their generation in a coordinated manner through mechanisms –- 

in some cases centralized and in others not -- that regularly 

deal with such changes on both a short-term and a longer-term 

basis. Our analysis demonstrates that the emission reductions 

that can be achieved or supported by such generation shifts are 

substantial and of reasonable cost. Further, both the 

achievability of this building block and the reasonableness of 

its costs are supported by the fact that there has been a 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 
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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 

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 
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generation by NGCC units over baseline levels can also serve as 

the basis for creation of CO2 emission rate credits (ERCs) –- 

that is, instruments representing the ability of incremental 

electricity generated by NGCC units to cause emission reductions 

at affected steam EGUs, as distinct from the incremental 

electricity itself. Again, it is important to note that the 

acquisition of such ERCs represents an investment in the actions 

of the facility or facilities whose alteration of utilization 

levels generated the emissions rate improvement or reduction. In 

the context of the BSER, purchase of instruments representing 

the emissions-reducing benefit of an action is simply a medium 

of investment in the underlying emissions reduction action. 

These mechanisms are discussed further in section V.A.5. In this 

rule, the EPA is establishing minimum criteria for the creation 

of valid ERCs by NGCC units and for the use of such ERCs by 

affected steam EGUs for demonstrating compliance with emission 

rate-based standards of performance established under state 

plans. The existence of minimum criteria will ensure that 

crediting mechanisms are feasible and will facilitate the 

development of organized markets to simplify the process of 

buying and selling ERCs. The minimum criteria are discussed in 

section VIII of this preamble. 
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 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 

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 
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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.370 With respect to energy impacts, 

building block 2 represents replacement of electrical energy 

from one generator with electrical energy from another generator 

that consumes less fuel, so the overall energy impact should be 

a reduction in fuel consumption by the overall source category 

as well as by individual affected coal-fired steam EGUs. 

Although 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 

 

370 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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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.371 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, 

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 highly substitutable service, and in 

the context of CO2 emissions, where location is not a 

consideration, in contrast with other pollutants, a measure that 

takes advantage of that integration to reduce CO2 emissions from 

 

371 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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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). Standards of performance that 

incorporate emissions trading and other multi-unit compliance 

approaches can facilitate the implementation of such a “system” 

and such approaches have already been used in the electricity 

industry to address CO2 as well as other pollutants, as discussed 

above. 

c. Building block 3. Building block 3 –- 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 

generating capacity to reduce emissions from affected sources is 

technically feasible, 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 
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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 ERCs. An affected EGU 

investing in incremental RE generation may choose to reduce its 

own generation by a corresponding amount or may choose to allow 

the reduction in generation to occur at other affected EGUs 

through the coordinated planning and operation of the 

interconnected electricity system. An affected EGU can also 

invest in RE generation by means of engaging in emissions 

trading where it is operating under a standard of performance 

that incorporates trading. 

 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the measures in building 

block 3 are discussed in Section V.E. below. We consider 

construction and operation of expanded RE generating capacity to 

be proven, well-established practices within the industry 

consistent with recent industry trends. States are already 

pursuing policies that encourage production of greater amounts 

of renewable energy, such as the establishment of targets for 

procurement of renewable generating capacity. Moreover, markets 

are likely to develop for emission rate credits that would 

facilitate investment in increased RE generation as a means of 
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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 

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 
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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 

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 
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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 

sources in the source category may appropriately be deemed 

components of a “system of emission reduction.” 
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 The renewable capacity measures in building block 3 

generally perform well against other BSER criteria. Generation 

from wind turbines and solar voltaic installations, two common 

renewable technologies, does not produce solid waste or require 

cooling water, a better environmental outcome than if that 

amount of generation had instead been produced at a typical 

range of fossil fuel-fired EGUs. With respect to energy impacts, 

fossil fuel consumption will decrease both for the source 

category as a whole and for individual affected EGUs. Although 

the variable nature of generation from renewable resources such 

as wind and solar units requires special consideration from grid 

operators to address possible changes in operating reserve 

requirements, renewable generation has grown quickly in recent 

years, as discussed above, and grid planners and operators have 

proven capable of addressing any consequent changes in 

requirements through ordinary processes. The EPA 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 

adverse energy impacts. With respect to technological 
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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.372 

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 

 

372 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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2 to replace higher-emitting generation and to deploy building 

block 3 to replace any emitting generation are not exhausted. 

Thus, as the system of emission reduction is expanded to include 

each of these building blocks, the emission reductions that will 

be achieved increase. 

Because the stringency and timing of emission reductions 

achievable through use of each individual building block have 

been set based on what is achievable at reasonable cost rather 

than the maximum achievable amount, the stringency of the 

combination of building blocks is also reasonable, and the 

combination provides headroom and additional flexibility for 

states in setting standards of performance and for sources in 

complying with those standards to choose among multiple means of 

reducing emissions. 

With respect to the quantity of emission reductions 

expected to be achieved from building block 1 in particular, the 

BSER encompassing all three building blocks is a substantial 

improvement over building block 1 in isolation. As noted 

earlier, the EPA is concerned that implementation of building 

block 1 in isolation 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 
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thereby lower their variable operating costs, building block 1 

if implemented in isolation would make those EGUs more 

competitive relative to other, lower-emitting fossil fuel-fired 

EGUs, possibly resulting in increased generation and higher 

emissions from the affected steam EGUs in spite of their lower 

emission rates. Combining building block 1 with the other 

building blocks addresses this concern by ensuring that 

owner/operators of affected steam EGUs as a group would have 

appropriate incentives not only to improve the steam EGUs’ 

efficiency but also to reduce generation from those EGUs 

consistent with replacement of generation by 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 
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the respective building block in isolation to the same degree of 

stringency. The EPA recognizes that as increasing quantities of 

generation from higher-emitting EGUs are replaced, the avoided 

cost of the generation that is being replaced by lower- or nonemitting generation decreases, but 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 availability to states of standards of 

performance that allow the use of emissions trading or other 

multi-unit compliance approaches 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 
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affected steam EGUs would in fact reduce their emissions if 

building block 1 were implemented in isolation).373 However, we 

believe that the cost of emission reductions achieved through 

heat rate improvements in the context of a three-building block 

BSER will remain reasonable for two reasons. First, as discussed 

in section V.C. below, 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 

 

373 If an EGU produces less generation output, then an 

improvement in that EGU’s heat rate and rate of CO2 emissions per 

unit of generation produces a smaller reduction in CO2 emissions. 

If the investment required to achieve the improvement in heat 

rate and emission rate is the same regardless of the EGU’s 

generation output, then the cost per unit of CO2 emission 

reduction will be higher when the EGU’s generation output is 

lower. Commenters have also stated that operating at lower 

capacity factors may cause units to experience deterioration in 

heat rates. 
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where to invest in heat rate improvements, with the result that 

there will be a tendency for such investments to be concentrated 

in EGUs whose generation output is expected to decrease the 

least. This enlightened bias in spending on heat rate 

improvements –- that is, focusing investments on EGUs where such 

improvements will have the largest impacts and produce the 

highest returns, given consideration of projected changes in 

dispatch patterns –- will tend to mitigate any deterioration in 

the cost of CO2 emission reductions achievable through heat rate 

improvements. 

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 XI, 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 
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historically in response to changes in factors such as weather 

and fuel supply. Further, the costs tend to decline over time as 

states and regulated entities take advantage of the available 

flexibility and expand deployment of more cost-effective 

measures (notably demand-side energy efficiency). The EPA 

considers this analysis strong confirmation of the 

reasonableness of the costs of the measures in the three 

building blocks in combination as the best system of emission 

reduction. 

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. 

e. Other combinations of the building blocks. The EPA has 

considered whether other combinations of the building blocks, 

such as a combination of building blocks 1 and 2 or a 

combination of building blocks 1 and 3, could be the BSER. We 

believe that any such combination is technically feasible and 

would be a “system of emission reduction” capable of achieving 

meaningful reductions in CO2 emissions from affected EGUs at a 
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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 

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. 
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5. Actions under the BSER that sources can take to achieve 

standards of performance 

 Based on the determination of the BSER described above, the 

EPA has identified a performance rate of 1305 lbs. per net MWh 

for affected steam EGUs and a performance rate of 770 lbs. per 

net MWh for affected stationary combustion turbines. The 

computations of these performance rates and the determinations 

of state goals reflecting these rates are described in sections 

VI and VII of the preamble, respectively. 

 Under section 111(d), states determine the standards of 

performance for individual sources. The EPA is authorizing 

states to express the standards of performance applicable to 

affected EGUs as either emission rate-based limits or mass-based 

limits. As described above, the sets of actions that sources can 

take to comply with these standards are another expression of 

the BSER, viewed through an individual-source lens. 

 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). 
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 Directly investing in, or purchasing emission rate credits 

created as a result of, incremental generation from 

existing NGCC units (building block 2). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, generation from new or up-rated RE 

generators (building block 3). 

 Reducing its utilization, coupled with direct investment in 

or purchase of emission rate credits representing building 

blocks 2 and 3 as indicated above. 

 Investing in surplus emission rate reductions at other 

affected EGUs through the purchase of rate-based emission 

credits or the use of other multi-unit compliance 

approaches (e.g., averaging). 

 A source to which a state applies a mass-based limit can 

achieve the limit through a combination of the following set of 

measures (to the extent allowed by the state plan), all of which 

are likewise components of the BSER: 

 Reducing its heat rate (building block 1). 

 Reducing its utilization and allowing its generation to be 

replaced or avoided through the routine operation of 

industry reliability planning mechanisms and market 

incentives. 
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 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 

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 
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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 

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. 
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 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, the existence of a clearly 

feasible path for usage of ERCs ensures that emission reductions 

achievable through implementation of the measures in building 

blocks 2 and 3 are available to assist all affected EGUs in 

achieving compliance with standards of performance based on the 

BSER. 

 (1) Building block 1. 

 The owner/operator of an affected steam EGU can take steps 

to reduce the unit’s heat rate, thereby lowering the unit’s CO2

emission rate. Examples of actions in this category are included 

in section V.C. below and in the GHG Mitigation Measures TSD for 
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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 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. 
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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 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 

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 
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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. Further details are provided in section VIII. 

 The owner/operator of an affected steam EGU would use the 

ERCs it has acquired for compliance –- whether acquired through 

ownership of NGCC capacity, a bilateral transaction, or an 

intermediated transaction –- by adding the ERCs to its measured 

net generation when computing its CO2 emission rate for purposes 

of demonstrating compliance with its emission rate-based 

standard of performance. 

 (3) Building block 3. 

 The owner/operator of an affected EGU can average the EGU’s 

emission rate with 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 
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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. 

 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 
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adequate administrative process for tracking credits to avoid 

double-counting and to facilitate enforceability of emission 

limits. 

 The types of RE generating capacity used by the EPA to 

quantify building block 3 are zero-emitting units. Under the 

definition of ERCs described above, each MWh of incremental 

generation by qualifying new RE generating capacity therefore 

can qualify as the basis for issuance of an ERC representing a 

full zero-emissions MWh.374 Further details are provided in 

section VIII. 

 As with building block 2, the owner/operator of an affected 

EGU would use the ERCs it has acquired for compliance –- whether 

acquired through ownership of qualifying RE generating capacity, 

a bilateral transaction, or an intermediated transaction –- by 

adding the ERCs to its measured net generation when computing 

its CO2 emission rate for purposes of demonstrating compliance 

with its emission rate-based standard of performance. 

 (4) Reduced generation. 

 The owner/operator of an affected EGU can reduce the unit’s 

generation and reflect that reduction in the form of a lower 

 

374 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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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 (unless the unit retires, reducing its emission rate to 

zero). However, if the owner/operator does average ERCs or 

qualifying cleaner generation into the unit’s emission rate, 

then a proportional reduction in both the numerator and the 

portion of the denominator representing the unit’s measured 

generation will amplify the effect of the acquired ERCs in the 

computation, with the result that the more the unit reduces its 

generation, the fewer ERCs will be needed to reach a given 

emission rate-based 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. 
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 (5) Emissions trading or other multi-unit compliance 

approaches. 

 To the extent allowed under standards of performance that 

incorporate emissions trading or otherwise through the relevant 

section 111(d) plans, the owner/operator of an affected EGU can 

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. 

 Under an emissions trading approach, the owner/operator of 

the affected EGU can acquire surplus credits through common 
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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 and/or standards of performance established 

thereunder authorize emissions trading. While the opportunity to 

acquire credits through common ownership might not extend to 

owner/operators of single EGUs or small fleets, all 

owner/operators would have the ability to engage in bilateral or 

intermediated purchase transactions for credits just as they can 

engage in transactions for other kinds of goods and services. 

 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. Further details are provided in section 

VIII. 

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 
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type of owner/operator can take advantage of this measure. 

Although some action or combination of actions to increase 

lower-carbon generation or reduce electricity demand somewhere 

in the interconnected electricity system of which the affected 

EGU is a part will be required to enable electricity supply and 

demand 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 
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allows other participants in the interconnected electricity 

system to play that role. 

 (3) Emissions trading or other multi-unit compliance 

approaches. 

 To the extent allowed under the relevant section 111(d) 

plans -- as the record indicates that it 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 
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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 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 
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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 

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 
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(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 

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 fuel-
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fired 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 

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 are discussed below in section VIII on 

state plans. The EPA notes that this is not an exhaustive list 

of non-BSER measures that could be employed to reduce CO2

emissions from affected EGUs. 

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. 
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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 

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 
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discussion of these measures is also provided in the GHG 

Mitigation Measures TSD for the CPP Final Rule. 

 (1) Heat rate improvement at affected EGUs other than coalfired steam EGUs. 

 Building block 1 reflects the opportunity to improve heat 

rate at coal-fired steam EGUs but not at other affected EGUs. As 

the EPA stated at proposal, the potential CO2 reductions 

available from heat rate improvements at coal-fired steam EGUs 

are much larger than the potential CO2 reductions available from 

heat rate improvements at other types of EGUs, and comments 

offered no persuasive basis for reaching a different conclusion. 

Nevertheless, we recognize that there may be instances where an 

owner/operator finds heat rate improvement to be an attractive 

option at a particular non-coal-fired affected EGU, and nothing 

in the rule prevents the owner/operator from implementing such a 

measure and using it to help achieve a standard of performance. 

 (2) Carbon capture and storage at affected EGUs. 

 Another approach for reducing CO2 emissions per MWh of 

generation from affected EGUs is the application of carbon 

capture and storage (CCS) technology. Consistent with the June 

2014 proposal, we are determining that use of full or partial 

CCS technology should not be part of the BSER for existing EGUs 
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because it would be more expensive than the measures determined 

to be part of the BSER, particularly if applied broadly to the 

overall source category. At the same time, we note that retrofit 

of CCS technology may be a viable option at some individual 

facilities, particularly where the captured CO2 can be used for 

enhanced oil recovery (EOR). For example, construction of one 

CCS retrofit application with EOR has already been completed at 

a unit at the Boundary Dam plant in Canada, and construction of 

another CCS retrofit application with EOR is underway at the 

W.A. Parish plant in Texas. We expect the costs of CCS to 

decline as implementation experience increases. CO2 emission rate 

reductions achieved through retrofit of CCS technology would be 

available to help affected EGUs achieve emission limits 

consistent with the BSER. 

 (3) Fuel switching to natural gas at affected EGUs. 

 In the proposal we discussed the opportunity to reduce CO2

emissions at an individual affected EGU by switching fuels at 

the EGU, particularly by switching from coal to natural gas. 

Most coal-fired EGUs could be modified to burn natural gas 

instead, and the potential CO2 emission reductions from this 

measure are large – approximately 40 percent in the case of 

conversion from 100 percent coal to 100 percent natural gas, and 
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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 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. 
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 Some affected EGUs may seek to control or reduce their CO2

emission contributions to the atmosphere by co-firing qualifying 

biomass with fossil fuels. The EPA recognizes that the use of 

some biomass-derived fuels can play an important role in 

controlling or reducing the contribution of CO2 emissions to the 

atmosphereAs 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. 

Section VIII.G.1.a (2) describes the process and considerations 

that states must make when proposing to use different kinds of 

biomass in state plans. 

 (5) Waste heat-to-energy conversion at affected EGUs. 

 Certain affected EGUs in urban areas or located near 

industrial or commercial facilities with needs for thermal 

energy may be able add new equipment to capture some of the 

waste heat from their electricity generation processes and use 

it to create useful thermal output, thereby engaging in combined 

heat and power (CHP) production. While the set of affected EGUs 

in locations making this measure feasible may be limited, where 

feasible the potential CO2 emission rate improvements can be 
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substantial: depending on the process used, the efficiency with 

which fuel is converted to useful energy can be increased by 25 

percent or more. The final rule allows an owner/operator 

applying CHP technology to an affected EGU to account for the 

increased efficiency by counting the useful thermal output as 

additional MWh of generation, thereby lowering the unit’s 

computed emission rate and assisting with achievement of an 

emission rate-based standard of performance. (The EPA notes that 

unless the unit also reduced its fuel usage, the addition of the 

capability to capture waste heat and produce useful thermal 

output would not reduce the unit’s mass emissions and therefore 

would not directly help the unit achieve a mass-based standard 

of performance.375)

b. Non-BSER measures that reduce CO2 emissions by reducing fossil 

fuel-fired generation. A second group of non-BSER measures has 

the potential to reduce CO2 emissions from affected EGUs by 

reducing the amount of generation from those EGUs. As discussed 

above, under a section 111(d) plan with mass-based standards of 

performance, no special action is required to enable measures of 

 

375 However, the EPA notes that a state could establish a 

mechanism for encouraging affected EGUs to apply CHP technology 

under a mass-based plan, for example, through awards of emission 

allowances to CHP projects. 
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this nature to help the source category as a whole and 

individual affected EGUs achieve their emission limits, because 

the CO2-reducing effects are captured in monitored stack 

emissions. However, under a section 111(d) plan with rate-based 

standards of performance, 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 state prefers to develop a plan reflecting the 

state measures approach discussed in section VIII below. We also 
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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 
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the owner/operators to completion of the units is essential in 

order to realize that result. Accordingly, a section 111(d) plan 

may rely on ERCs issued on the basis of generation from these 

units and other new nuclear units. For the same reason, a plan 

may rely on ERCs issued on the basis of generation from up-rates 

to the capacity of existing nuclear units. 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 
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technologies quantified for the BSER because they are generally 

more expensive than the measures that were included and the 

other measures in the BSER. However, these technologies are 

equally capable of replacing generation from affected EGUs and 

thereby reducing CO2 emissions. Further, as with any technology, 

there are likely to be certain circumstances where the costs of 

these technologies are more attractive relative to alternatives, 

making the technologies likely to be deployed to some extent. 

Indeed, distributed solar is already being widely deployed in 

much of the United States and offshore wind, while still unusual 

in this country, has been extensively deployed in some other 

parts of the world. We expect innovation in RE generating 

technologies to continue, making such technologies even more 

attractive over time. A section 111(d) plan may rely on ERCs 

issued on the basis of generation from new and uprated 

installations of these technologies. The plan provisions to 

accommodate ERCs issued on the basis of generation from these RE 

generating technologies again would be similar to the plan 

provisions necessary to accommodate ERCs issued on the basis of 

generation from other RE generating technologies (building block 

3). 

 (4) Non-zero-emitting RE generating technologies. 
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 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 

affected EGUs and thereby control or reduce CO2 emission 

contributions to the atmosphere.376 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 wastederived feedstocks and certain forest- and agriculture-derived 

industrial byproduct feedstocks when considering state plans. 

The EPA also expects that states’ reliance specifically on 

sustainably-derived agriculture- and forest-derived feedstocks 

may also be an approvable element of their state plans. The EPA 

 

376 The EPA and many states have recognized the importance of 

integrated waste materials management strategies that emphasize 

a hierarchy of waste prevention and all other productive uses of 

waste materials to reduce the volume of disposed waste materials 

(see section VIII for more discussion of waste to energy 

strategies). 
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and many states have recognized the importance of integrated 

waste materials management strategies that emphasize a hierarchy 

of waste prevention and all other productive uses of waste 

materials to reduce the volume of disposed waste materials. 

Because it is likely that more than one MWh of incremental 

generation from these technologies would be required as the 

basis qualifying for the issuance of an ERC worth a full MWh of 

zero-emitting generation, the minimum requirements to 

accommodate ERCs issued on the basis of generation from these 

technologies would be similar to the plan provisions necessary 

to accommodate ERCs issued on the basis of incremental 

generation from existing NGCC units (building block 2), 

supplemented by appropriate provisions to address special 

characteristics of the feedstocks. 

 (5) Waste heat-to-electricity conversion at non-affected 

facilities. 

 Industrial facilities that install new equipment to capture 

waste heat from an existing combustion process and then use the 

waste heat to generate electricity –- a form of combined heat 

and power (CHP) production –- can produce generation that 

replaces generation from affected EGUs and thereby reduces CO2

emissions. A section 111(d) plan may rely on ERCs issued on the 
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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. If no 

supplemental fuel is used to produce the electricity, this 

generation could be considered zero-emitting because the waste 

heat would have been produced by the industrial process anyway. 

To the extent that 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 zero-emitting generation similar to an ERC issued on the 

basis of building block 3. In order to permit ERCs issued on the 

basis of generation from facilities where the waste heat input 

is supplemented by fossil fuel input, the plan would need to 

include appropriate provisions for establishing the number of 

incremental MWh that would be generated in order to serve as the 

basis for issuance of each ERC worth one full MWh of 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. 
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 Reductions of electricity line losses incurred from the 

transmission and distribution system between the points of 

generation and the points of consumption by end-users allow the 

same overall demand for electricity services to be met with a 

smaller overall quantity of electricity generation. Such 

reductions in generation quantities would tend to reduce 

generation by affected EGUs, thereby reducing CO2 emissions. The 

opportunity for improvement is large because, on average, line 

losses account for approximately seven percent of all 

electricity generation. The EPA recognizes that, in general, 

only the owner/operators of the transmission and distribution 

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 
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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 

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, building block 2, building block 3, and all 

combinations of the building blocks (implemented on the 
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schedules and at the stringencies determined to be reasonable in 

this rule) would achieve meaningful degrees of emission 

reductions,377 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 

of the data and procedures necessary to determine recomputed 

state goals using any combination of the building blocks are set 

forth in the CO2 Emission Performance Rate and Goal Computation 

TSD for the CPP Final Rule available in the docket. 

B. Legal Discussion of Certain Aspects of the BSER 

This section includes a legal analysis of various aspects 

of EPA’s determination of the BSER, including responses to some 

of the major adverse comments. These aspects include (1) the 

EPA’s authority to determine the BSER; (2) the approach to 

subcategorization; (3) the EPA’s basis for determining that 

 

377 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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building blocks 2 and 3 qualify as part of the BSER under CAA 

sections 111(d)(1) and (a)(1), notwithstanding commenters’ 

arguments that these building blocks cannot be considered part 

of the BSER because they are not based on measures integrated 

into the design or operation of the affected source’s own 

production processes or methods or because they are dependent on 

actions by entities other than the affected source; (4) the 

relationship between an affected EGU’s implementation of 

building blocks 2 and 3 and CO2 emissions reductions; (5) the 

EPA’s basis for including reduced generation as a component of 

the BSER; (6) reasons why, contrary to assertions by commenters, 

this rule is within the EPA’s statutory authority, is not 

inconsistent with the Federal Power Act or state laws governing 

public utility commissions, and does not result in what the U.S. 

Supreme Court described as “an enormous and transformative 

expansion in [the] EPA’s regulatory authority”;378 and (7) 

reasons that, contrary to assertions by commenters, the 

stringency of the BSER for this rule for CO2 emissions from 

existing affected EGUs is not inconsistent with the stringency 

 

378 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014). 
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of the BSER for the rules the EPA is promulgating at the same 

time for CO2 emissions from new or modified affected EGUs. 

1. The EPA’s authority to determine the BSER. 

In this section, we explain why the EPA, and not the 

states, has the authority to determine the BSER and, therefore, 

the level of emission limitation required from the existing 

sources in the source category in section 111(d) rulemaking and 

the associated state plans. 

CAA section 111(d)(1) requires the EPA to establish a 

section 110-like procedure under which each state submits a plan 

that “establishes standards of performance for any existing 

source of air pollutant” and “provides for the implementation 

and enforcement of such standards of performance.” As CAA 

section 111(d) was originally adopted in the 1970 CAA 

Amendments, however, state plans were required to establish 

“emission standards” – an undefined term -- rather than 

“standards of performance,” a term that was limited to CA 

section 111(b).379 The 1970 provision was in effect when the EPA 

 

379 See 1970 CAA Amendments, § 4, 84 Stat. at 1683-84. 

Subsequently, in 1977, Congress replaced the term “emission 

standard” with “standards of performance.” See 1977 CAA 

Amendments, § 109, 91 Stat. at 699. 
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issued the 1975 implementing regulationsfor CAA section 

111(d),380 which remain in effect to this day. 

These regulations establish a cooperative framework that is 

similar to that under CAA section 110. First, the EPA develops 

“emission guidelines” for source categories, which are defined 

as a final guideline document reflecting “the degree of emission 

reduction achievable through the application of the best system 

of emission reduction ... which the Administrator has determined 

has been adequately demonstrated.” Then, the states submit 

implementation plans to regulate any existing sources.381

The preamble to these regulations carefully considered the 

allocation of responsibilities as between the EPA and the states 

for purposes of CAA section 111(d), and concluded that the EPA 

is responsible for determining the level of emission limitation 

from the source category, while the states have the 

responsibility of assigning emission requirements to their 

sources that assured their achievement of that level of emission 

limitation.382 The EPA explained “that some substantive criterion 

 

380 See “State Plans for the Control of Certain Pollutants From 

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

381 See “State Plans for the Control of Certain Pollutants From 

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

382 As we made clear in the proposed rulemaking, we are not reopening these regulations (on the issue of the authority to 
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was intended to govern not only the Administrator’s promulgation 

of standards but also [her] review of state plans.”383 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.”384 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).”385 Thus, the implementing regulations make clear 

that the EPA is responsible for determining the level of 

emission limitation that the state plans must achieve. 

 

determine the BSER or any other issue, unless specifically 

indicated otherwise) in this rulemaking, and our discussion of 

these regulations in responding to comments does not constitute 

a re-opening. 

383 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53342 (Nov. 17, 1975). 

384 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 

385 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 
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In 1977, Congress revised CAA section 111(d) to require 

that the states adopt “standards of performance,” as defined 

under CAA section 111(a)(1). As noted above, a standard of 

performance is defined as “a standard for emissions of air 

pollutants which reflects the degree of emission limitation 

achievable through the application of the best system of 

emission reduction which ... the Administrator determines has 

been adequately demonstrated.” (Emphasis added.) By its terms, 

this provision provides that the EPA has the responsibility of 

determining whether the “best system of emission reduction” is 

“adequately demonstrated.” While the provision does not 

explicitly assign authority for determining the “best system of 

emission reduction,” the logical implication is that Congress 

assigned that role to the Administrator by requiring the 

Administrator to determine whether the “best system of emission 

reduction” is also “adequately demonstrated.” Even if the 

provision may be considered to be silent or ambiguous on that 

question, the EPA reasonably interprets the provision under 

Chevron step 2to assign the responsibility of identifying the 

“best system of emission reduction” to the Administrator for the 

same reasons discussed in the preamble to the 1975 implementing 

regulations. 

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In addition, in the legislative history of the 1977 CAA 

Amendments, when Congress replaced the term “emission standards” 

under CAA section 111(d)(1) with the term “standards of 

performance,” Congress endorsed the overall approach of the 

implementing regulations, which lends further credence to the 

proposition that the EPA has the responsibility for determining 

the “best system of emission reduction” and the amount of 

emission limitation from the existing sources.Specifically, in 

the House report that introduced the substantive changes to CAA 

section 111, the Committee explained that “[t]he Administrator 

would establish guidelines as to what the best system for each 

category of existing sources is.”386 States, on the other hand, 

“would be responsible for determining the applicability of such 

guidelines to any particular source or sources.”387 The use of 

the term “guidelines,” which does not appear in CAA section 

111(d), indicates Congress was aware of and approved of the 

approach taken in the EPA’s implementing regulations for 

establishing guidelines, which determine the BSER. At a minimum, 

if Congress disapproved of the EPA’s implementing regulations, 

 

386 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 387 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 
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we would not expect the House report to adopt the EPA’s 

terminology to clarify CAA section 111(d). 

In addition, Congress expressly referred to our 

“guidelines” in CAA section 129, added as part of the 1990 CAA 

Amendments. , Congress added CAA section 129 to address solid 

waste combustion and specifically directed the Administrator to 

establish “guidelines (under section 111(d) and this section) 

and other requirements applicable to existing units.”388 This 

reference also indicates that Congress was aware of and approved 

the EPA’s regulations under section 111(d). 

The EPA has followed the same approach described in the 

implementation regulations in all its rulemakings under section 

111(d). Thus, in all cases, the EPA has identified the type of 

emission controls for the source category and the level of 

emission limitation based on those controls.389 The EPA’s 

 

388 CAA section 129(a)(1)(A) (emphasis added). 389 See Part 60, Subpart Ca (large municipal waste combustors), 

56 Fed. Reg. 5514 (Feb. 11, 1991), 40 C.F.R. § 60.30a-.39a 

(subsequently withdrawn and superseded by Subpart Cb, see 60 

Fed. Reg. 65,387 (Dec. 19, 1995)); Subpart Cb (large municipal 

waste combustors constructed on or before September 20, 1994), 

60 Fed. Reg. 65,387 (Dec. 19, 1995), 40 C.F.R. § 60.30b-.39b (as 

amended in 1997, 2001, and 2006); Subpart Cc (municipal solid 

waste landfills), 61 Fed. Reg. 9905 (Mar. 12, 1996), 40 C.F.R. § 

60.30c-.36c (as amended in 1998, 1999, and 2000); Subpart Cd 

(sulfuric acid production units), 60 Fed. Reg. 65,387 (Dec. 19, 

1995), 40 C.F.R. § 60.30d-.32d; Subpart Ce 
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longstanding and consistent interpretation of CAA section 111(d) 

is also “evidence that the statute is in fact not ambiguous,” 

and that the EPA’s interpretation should be adopted.390 

 Commenters argued that the states should be given the 

authority to determine the best system of emission reduction 

and, therefore, the level of emission limitation from their 

sources., For the reasons just discussed, this is an incorrect 

 

(hospital/medical/infectious waste incinerators), 62 Fed. Reg. 

48,348 (Sept. 15, 1997), 40 C.F.R. § 60.30e-.39e (as amended in 

2009 and 2011); Subpart BBBB (small municipal waste combustion 

units constructed on or before August 30, 1999), 65 Fed. Reg. 

76,738 (Dec. 6, 2000), 40 C.F.R. § 60.1500-.1940; Subpart DDDD 

(commercial and industrial solid waste incineration units that 

commenced construction on or before November 30, 1999), 65 Fed. 

Reg. 75,338 (Dec. 1, 2000), 40 C.F.R. § 60.2500-.2875 (as 

amended in 2005, 2011, and 2013); Subpart FFFF (other solid 

waste incineration units that commenced construction on or 

before December 9, 2004), 70 Fed. Reg. 74,870 (Dec. 16, 2005), 

40 C.F.R. § 60.2980-.3078 (as amended in 2006); Subpart HHHH 

(coal-electric utility steam generating units), 70 Fed. Reg. 

28,606 (May 18, 2005) (subsequently vacated by the D.C. Circuit 

in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008)); Subpart 

MMMM (existing sewage sludge incineration units), 76 Fed. Reg. 

15,372 (Mar. 21, 2011), 40 C.F.R. § 60.5000-.5250; “Phosphate 

Fertilizer Plants, Final Guideline Document Availability,” 42 

Fed. Reg. 12,022 (Mar. 1, 1977) (not codified); “Kraft Pulp 

Mills; Final Guideline Document; Availability,” 44 Fed. Reg. 

29,828 (May 22, 1979) (not codified); and “Primary Aluminum 

Plants; Availability of Final Guideline Document,” 45 Fed. Reg. 

26,294 (Apr. 17, 1980) (not codified). 

390 See Riverkeeper v. Entergy, [cite]; Scalia, Antonin, Judicial 

Deference to Administrative Interpretations of Law, 1989 Duke 

L.J. 511, 518.
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interpretation of CAA section 111(d)(1) and (a)(1), and we are 

not compelled to abandon our longstanding practice. 

2. Approach to subcategorization. 

 As noted above, in this rule, we are treating all fossil 

fuel-fired EGUs as a single category, and, in the emission 

guidelines that we are promulgating with this rule, we are 

treating steam EGUs and combustion turbines as separate 

subcategories. We are determining the BSER for steam EGUs and 

the BSER for combustion turbines, and applying the BSER to each 

subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. 

 This approach is fully consistent with the provisions of 

section 111(d), which simply require the EPA to determine the 

BSER, do not prescribe the method for doing so, and are silent 

as to subcategorization. This approach is also fully consistent 

with other provisions in CAA section 111, which require the EPA 

first to list source categories that may reasonably be expected 

to endanger public health or welfare391 and then to regulate new 

sources within each such source category,392 and which grant the 

 

391 CAA section 111(b)(1)(A). 392 CAA section 111(b)(1)(B). 
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EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.393 

 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 including 

investment in the building blocks, replacing or reducing 

generation, and emissions trading, as enabled or facilitated by 

the implementation programs the states adopt. Further, in the 

case of a rate-based state plan, several other compliance 

options not included in the BSER for this rule are also 

available to all affected sources, including investment in 

demand-side energy efficiency measures. Such compliance options 

help affected sources achieve compliance under a mass-based 

plan, even if indirectly. 

 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 

 

393 CAA section 111(b)(2). 
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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. 

3. Building blocks 2 and 3 as a “system of emission reduction”

a. Overview. As we explain above, the emission performance rates 

that we include in this rule’s emission guidelines are 

achievable by the affected EGUs through the application of the 

BSER, which includes the three building blocks. Commenters 

object that building blocks 2 (generation shift) and 3 

(renewable energy) cannot, as a legal matter, be considered part 

of the BSER under CAA section 111(d)(1) and (a)(1). These 

commenters explain that in their view, under CAA section 111, 

the emission performance rates must be based on, and therefore 

the BSER must be limited to, methods for emissions control that 

the owner/operator of the affected source can integrate into the 

design or operation of the source itself, and cannot be based on 
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actions taken beyond the source or actions involving third-party 

entities.394 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 

 

394 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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reduction,” by its terms and when read in context, contains no 

such limits. To the contrary, its plain meaning is deliberately 

broad and, under Chevron, 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. Such actions include the measures in 

building blocks 2 and 3, which when implemented by an affected 

source enable the source to achieve their emission limits 

because of the unique characteristics of the utility power 

sector. For purposes of this rule, we consider a “system of 

emission reduction” -- as defined under CAA section 111(a)(1) 

and applied under CAA section 111(d)(1) -– to encompass a broad 

range of pollution-reduction actions,395 which includes the 

measures in building blocks 2 and 3. 

Our interpretation that a “system of emission reduction” is 

broad enough to include the measures in building blocks 2 and 3 

is supported by the following: our interpretation of CAA section 

 

395 Because of its breadth and general nature, we suggest that 

the phrase “system of emission reduction” may be envisioned as a 

“big toolbox.” 
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111(a)(1) is consistent with its plain meaning and statutory 

context; the phrase “system of emission reduction” accommodates 

the very design of CAA section 111(d)(1), which covers a range 

of source categories and air pollutants;396 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 through 

comparisons to CAA provisions that give the EPA similar 

authority to consider such measures and through comparisons to 

CAA provisions that would preclude the EPA from considering such 

measures. 

To the extent the phrase “system of emission reduction” is 

ambiguous, the EPA's interpretation is reasonable 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 

 

396 Because it is designed to apply to a range of air pollutants 

not regulated under other provisions, CAA section 111(d) may be 

described as a “catch-all” or “gap-filler.” As such, a “system 

of emission reduction” as applied under CAA section 111(d) 

should be interpreted flexibly to accommodate this role. 
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EGUs are already implementing the measures in these building 

blocks for various reasons, including for purposes of reducing 

CO2 emissions. (iii) Interpreting the phrase “system of emission 

reduction” to incorporate building blocks 2 and 3 is consistent 

with (a) other provisions in the CAA, including the acid rain 

provisions in Title IV and the SIP provisions in CAA section 

110, along with the EPA’s regulations implementing the CAA SIP 

requirements concerning interstate transport and regional haze, 

each of which is based on at least some of the same measures 

included in building blocks 2 and 3; (b) prior EPA action under 

CAA section 111(d), including the 2005 Clean Air Mercury Rule,397

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) 

 

397 This rule was vacated by the D.C. Circuit on other grounds. 

New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), cert. 

denied sub nom. Util. Air Reg. Grp. v. New Jersey, 555 U.S. 1169 

(2009). 
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Lastly, interpreting the phrase “system of emission reduction” 

to authorize the EPA, in formulating its BSER determination, to 

weigh a broad range of emission-reducing measures that includes 

building blocks 2 and 3 is consistent with Congress’s intent to 

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 would be able to 

develop the innovative solutions necessary to protect public 

health and welfare. 

Congress passed the CAA, including its several amendments, 

to protect public health and welfare from “mounting dangers,” 

including “injury to agricultural crops and livestock, damage to 

and the deterioration of property, and hazards to air and ground 

transportation.”398 In doing so, Congress established numerous 

programs to address air pollution problems and provided the EPA 

with guidance and flexibility in carrying out many of those 

programs. In the context of this industry and this pollutant it 

is reasonable to reject the interpretation urged by commenters 

that the “system of emission reduction” applicable to the 

affected EGUs must be limited to measures integrated into the 

design or operation of the source itself. Adopting such an 

 

398 CAA section 101(a)(2). 
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interpretation would limit the “system of emission reduction” to 

measures that are either substantially more expensive or 

substantially less effective at reducing emissions than the 

measures in building blocks 2 and 3, notwithstanding the absence 

of any statutory language imposing such a limit. Such a result 

would be contrary to the goals of the CAA and would ignore the 

facts that sources in this industry routinely address planning 

and operating objectives on a broad, multi-source basis using 

the measures in building blocks 2 and 3 and would seek to use 

building blocks 2 and 3 (as well as non-BSER measures) to comply 

with whatever emission standards are set as a result of this 

rule. Indeed, as already observed, building blocks 2 and 3 are 

already being used to reduce emissions, and to do so 

specifically by operation of the industry’s inherent multisource functions. 

b. System of emission reduction as a broad range of measures 

under Chevron step 1. 

(1) Plain meaning and context of “system of emission 

reduction.” 

 The phrase “system of emission reduction” appears in the 

definition of a “standard of performance” under CAA section 

111(a)(1). That definition reads: 

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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. 

These provisions make clear that the purpose of the “system 

of emission reduction” is to serve as the basis for the emission 

limitation. In addition, 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. Under CAA section 111(d)(1), such a limit is 

established for “any existing source,” which is defined as any 

existing “building, structure, facility, or installation which 

emits or may emit any air pollutant.”399 The term “system” is not 

defined in the CAA. As a result, that term should be given its 

ordinary meaning, which is “a set of things working together as 

parts of a mechanism or interconnecting network; a complex 

 

399 See CAA section 111(d)(1) (applying a standard of performance 

to any existing source); (a)(6) (defining the term “existing 

source” as any stationary source other than a new source); and 

(a)(3) (defining the term “stationary source” as “any building, 

structure, facility, or installation which emits or may emit any 

air pollutant,” however, explaining that “[n]othing in 

subchapter II [i.e., Title II] of this chapter relating to 

nonroad engines shall be construed to apply to stationary 

internal combustion engines.”) 

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whole.”400 With this definition, the phrase “system of emission 

reduction” takes a broad meaning: a set of things that work 

together to reduce emissions. 

 When read in context, the phrase “system of emission 

reduction” carries important limitations: because the “degree of 

emission limitation”must be “achievablethrough the application 

of the best system of emission reduction,”the “system of 

emission reduction” must be limited to “a set of things” that 

can be implemented by the sources themselves. 

As a practical matter, the “source” includes the “owner or 

operator” of any building, structure, facility, or installation 

for which a standard of performance is applicable. Under CAA 

section 111(e), it is the “owner or operator” of a source who is 

prohibited from operating “in violation of any standard of 

performance applicable to such source.”401

 

400 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”). 

401 While this section provides for enforcement in the context of 

new sources, a CAA section 111(d) plan must provide for the 

enforcement of a standard of performance for existing sources. 

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Thus, a “system of emission reduction” for purposes of CAA 

section 111(d) means “a set of things” that source owners or 

operators can implement to achieve an emission limitation 

applicable to their existing source.402 In contrast, a “system of 

emission reduction” does not include actions that only a state 

or other governmental entity could take that would have the 

effect of reducing emissions from the source category, and that 

are beyond the ability of the affected sources’ owners/operators 

to take or control.. Additionally, actions that a source owner 

or operator could take that would not have the effect of 

reducing emissions, such as purchasing offsets, would also not 

qualify as a “system of emission reduction.” 

Building blocks 2 and 3 each fall within the meaning of a 

“system of emission reduction” because they consist of measures 

that the owners/operators of the affected EGUs can implement to 

achieve their emission limits. In doing so, the affected EGUs 

will achieve the overall emission reductions the EPA identifies 

in this rule. We describe these building block 2 and 3 measures 

 

402 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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in detail elsewhere in this rule, including the specific actions 

that owners/operators of affected EGUs can take to implement the 

measures. 

It should be noted that defining the scope of a “system of 

emission reduction” is not the end of our inquiry under CAA 

section 111(a)(1); rather, as noted above, a standard of 

performance must reflect the application of the “best system of 

emission reduction ... adequately demonstrated.” (Emphasis 

added.) Thus, in determining the BSER, the Administrator must 

also determine whether the available systems of emission 

reduction are “adequately demonstrated,” based on the criteria, 

described above, set out by Congress in the legislative history 

and the D.C. Circuit in the caselaw. After identifying the 

“adequately demonstrated” systems of emission reduction, the 

Administrator then selects the “best” of these, based on several 

factors, including amount of emission reduction, cost, nonair 

quality health and environmental impact and energy requirements. 

Only after the Administrator weighs all of these considerations 

can she determine the BSER and, based on that, establish a 

standard of performance under CAA section 111(b) or an emission 

guideline under CAA section 111(d). 
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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 type 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. 

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. Further, these 

building blocks also satisfy the other statutory criteria 

enumerated in CAA section 111(a)(1). 

(2) Other indications that the BSER provisions encompass a 

broad range of measures. 
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The EPA’s plain meaning interpretation that the BSER 

provisions in CAA section 111(d)(1) and (a)(1) are designed to 

include a broad range of measures, including building blocks 2 

and 3, is supported by several other indications in the CAA and 

the legislative history of section 111. 

(a) Scope of CAA section 111(d)(1). 

First, the scope of CAA section 111(d)(1) supports our 

broad interpretation of the BSER because a wide range of control 

measures is appropriate for the wide range of source categories 

and air pollutants covered under CAA section 111(d). 

 In the 1970 CAA Amendments, Congress established a 

regulatory regime for existing stationary sources of air 

pollutants that may be envisioned as a three-legged stool, 

designed to address “three categories of pollutants emitted from 

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.403

Congress enacted CAA section 111(d) to cover this third category 

 

403 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 

implementing CAA section 111(d)). 
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of air pollutants and, in this sense, Congress designed it to 

apply to any air pollutants that were not otherwise regulated as 

toxics or NAAQS pollutants.404 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.405 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).406 In addition, in the 1990 CAA 

 

404 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.”). 

405 See Sen. Rep. No. 91-1196, p. 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420. 

406 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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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.407 Finally, it 

should be noted that Congress designed CAA section 111(d) to 

cover a wide range of source categories –- including any source 

category that the EPA identifies under subsection 111(b)(1)(A) 

as meeting the criteria of, in general, causing or contributing 

significantly to air pollution that may reasonably be 

anticipated to endanger public health or welfare -- along with 

the wide range of air pollutants. 

Because Congress designed CAA section 111(d) to cover a 

wide range of air pollutants -- including ones that Congress may 

not have been aware of at the time it enacted the provision –- 

 

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). 

407 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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and a wide range of industries, it is logical that Congress 

intended that the BSER provision, as applied to CAA section 

111(d), have a broad scope so as to accommodate the range of air 

pollutants and source categories. 

(b) Legislative history of CAA section 111. 

(i) Breadth of “system of emission reduction.” 

The phrase “system of emission reduction,” particularly as 

applied under CAA section 111(d), should be broadly interpreted 

consistent with its plain meaning but also in light of its 

legislative history. The version of CAA section 111(d)(1) that 

Congress adopted as part of the 1970 CAA Amendments read largely 

as CAA section 111(d)(1) does at present, except that it 

required states to impose “emission standards” on any existing 

source. (Congress replaced that term with “standards of 

performance” in the 1977 CAA Amendments.) The 1970 CAA 

Amendments version of CAA section 111(d)(1) neither defined 

“emission standards” nor imposed restrictions on the EPA in 

determining the basis for the emission standards.408 

 

408 Although not defined under CAA section 111, the term was used 

in other provisions and defined in some of them. The term was 

defined under the CAA’s citizen suit provision. See 1970 CAA 

Amendments, Pub. L. 91-604, § 12, 84 Stat. 1676, 1706 (Dec. 31, 

1970) (defined as “(1) a schedule or timetable of compliance, 

emission limitation, standard of performance or emission 
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For new sources, CAA section 111(b)(1)(B), as enacted in 

the 1970 CAA Amendments (and as it largely still reads), 

required the EPA to promulgate “standards of performance,” and 

defined that term, much like the present definition, as emission 

standards based on the “best system of emission reduction ... 

adequately demonstrated.” This quoted phrase was not included in 

either the House or Senate versions of the provision, and, 

instead, was added during the joint conference between the House 

and Senate. The conference report accompanying the text offers 

no clarifications. 

The House and Senate bills do, however, provide some 

insights. The House bill, H.R. 17255, would have required new 

sources of non-hazardous air pollutants to “prevent and control 

 

standard, or (2) a control or prohibition respecting a motor 

vehicle fuel or fuel additive....”). Congress also used it in the 

CAA’s NAAQS provisions and in CAA section 112. Under the CAA’s 

NAAQS provisions (i.e., the “Ambient Air Quality and Emission 

Standards” provisions), Congress directed the EPA to issue 

information on “air pollution control techniques,” and include 

data on “available technology and alternative methods of 

prevention and control of air pollution” as well as on 

“alternative fuels, processes, and operating methods which will 

result in elimination or significant reduction of emissions.” 

Id., § 4, 84 Stat. at 1679. Similarly, under CAA section 112, 

the Administrator was required to “from time to time, issue 

information on pollution control techniques for air pollutants” 

subject to emission standards. Id., 84 Stat. at 1685. These 

statements provide additional context for the term’s broad 

intent. 
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such emissions to the fullest extent compatible with the 

available technology and economic feasibility, as determined by 

the Secretary.”409 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.”410 The 

Senate Committee Report explains that “performance standards 

should be met through application of the latest available 

emission control technology or through other means of preventing 

or controlling air pollution.”411 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 

 

409 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. 

410 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added). 411 Sen. Rep. No. 91-1196 (Sept. 17, 1970), 1970 CAA Legis. Hist. 

at 415-16 (emphasis added). 
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operator determine the most economic, acceptable 

technique to apply.412 

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.413

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.414 

While the phrase “system of emission reduction” was not 

discussed in the Conference Report or discussed in either 

chamber during the debates over passage of the Conference 

 

412 Sen. Rep. No. 91-1196, pp. 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added). 

413 Notably, the Senate report identifies pollution control and

pollution prevention as objectives of the Senate provision. 

Pollution prevention is discussed more generally below as a 

“primary purpose” of the CAA, however, the report makes clear 

that pollution prevention measures – which the EPA understands 

to include such measures as building blocks 2 and 3 -- are 

appropriate under CAA section 111. 

414 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis 

added). 

Formatted: Highlight
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agreement, the final text appears to blend the broad spirit of 

S. 4358 (which required the “latest available control 

technology, processes, operating methods, or other 

alternatives”) with the cost concerns identified in H.R. 17255 

(which required consideration of “economic feasibility” when 

establishing federal emission standards for new stationary 

sources). This history strongly suggests that Congress intended 

to authorize the EPA to consider a wide range of measures in 

calculating a standard of performance for stationary sources. At 

a minimum, there is no indication that Congress intended to 

preclude certain measures or actions from the EPA’s assessment 

of the BSER. 

In 1977, Congress amended CAA section 111 to reflect a 

narrower conception of CAA section 111(a)(1). Congress was 

clear, however, that existing source standards, which were no 

longer developed as “emission standards,” would not be limited 

to technological measures. Specifically, the 1977 CAA Amendments 

revised CAA section 111(a)(1) to require all new sources to meet 

emission standards based on the reductions achievable through 

the use of the ”best technological system of continuous emission 

reduction.”415 According to the legislative history, [t]his 

 

415 CAA section 111(a)(1) (1977). 
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mean[t] that new sources may not comply merely by burning 

untreated fuel, either oil or coal.” 416 The new requirement 

stemmed in part from Congress’s concern over the shocks that the 

country experienced during the 1973-74 Arab Oil Embargo, which 

led Congress to revise CAA section 111 to “encourage and 

facilitate the increased use of coal, and to reduce reliance (by 

new and old sources alike), upon petroleum to meet emission 

requirements.”417 Imposing a new technological requirement (along 

with a new percentage reduction requirement) under CAA section 

111 was designed to “force new sources to burn high-sulfur fuel 

thus freeing low-sulfur fuel for use in existing sources where 

it is harder to control emissions and where low-sulfur fuel is 

needed for compliance.” 418 Congress nonetheless recognized that 

despite narrowing new source standards to the best 

“technological system of continuous emission reduction,” many 

“innovative approaches may in fact reduce the economic and 

energy impact of emissions control,” and the Administrator 

 

416 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

417 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

418 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 Fed. Reg. 33580, 33581-33582 

(June 11, 1979). 
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should still be encouraged to consider other technologically 

based techniques for emissions reduction, including 

“precombustion cleaning or treatment of fuels.”419 This is 

discussed in more detail below. 

Despite these changes with respect to new sources, the 1977 

CAA Amendments further reinforce the notion that with respect to 

existing sources, the BSER was never intended to be narrowly 

applied. In 1977, Congress changed CAA section 111(d)(1) to 

require that states adopt “standards of performance” and made 

clear that such standards were to be based on the “best system 

of continuous emission reduction ... adequately demonstrated,”420

but generally maintained the breadth of that term. Although 

Congress inserted the word “continuous” into the phrase, 

Congress explained that “standards in the Section 111(d) state 

plan would be based on the best available means (not necessarily 

technological) for categories of existing sources to reduce 

emissions.”421 This was intended to distinguish existing source 

 

419 H.R. Rep. No. 95-294, p. 189 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2656. 

420 CAA section 111(a)(1)(C) under the 1977 CAA Amendments. 421 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 
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standards from new source standards, for which “the requirement 

for [BSER] has been more narrowly redefined as best 

technological system of continuous emission reduction.”422,423

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.”424 Further, nothing in the 1990 CAA Amendments or 

 

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.”). 

422 Sen. Muskie, Sen. Consideration of the H.R. Conf. Rep. No. 

95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 

423 In 1977, Congress added a new substantive definition for 

“emission standard” generally applicable throughout the CAA. 

1977 CAA Amendments, Pub. L. 95-95, § 301, 91 Stat. 685, 770 

(Aug. 7, 1977) (defining “emission limitation” and “emission 

standard” as “a requirement established by the State or the 

Administrator which limits the quantity, rate, or concentration 

of emissions of air pollutants on a continuous basis, including 

any requirement relating to the operation or maintenance of a 

source to assure continuous emission reduction.”). Congress also 

added a generally applicable definition of standard of 

performance, defined as “a requirement of continuous emission 

reduction, including any requirement relating to the operation 

or maintenance of a source to assure continuous emission 

reduction.” Id. 424 We note that the general definition of a standard of 

performance at CAA section 302(l) still uses “continuous.” Even 

if this provision applies to section 111, it does not affect our 

analysis in this rule, including our interpretation that BSER 

includes building blocks 2 and 3. 
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their legislative history indicates that Congress intended to 

impose new constraints on the types of systems of emission 

reduction that could be considered under CAA section 111(d)(1) 

and (a)(1). In contrast, Congress retained the definition of the 

term “technological system of continuous emission reduction,” 

which means 

(A) a technological process for production or operation by 

any source which is inherently low-polluting or 

nonpolluting, or 

(B) a technological system for continuous reduction of the 

pollution generated by a source before such pollution is 

emitted into the ambient air, including precombustion 

cleaning or treatment of fuels. 

That term continues to be used in reference to new sources in 

certain circumstances, under CAA section 111(b), (h), and (j).425

 

425 In many respects, there are indications that Congress prefers 

CAA section 111(b) standards of performance to be based on 

technological control methods. This is due in part to the 

recognition that new sources have long operating lives over 

which initial capital costs can be amortized. Thus, new 

construction is the preferred time to drive capital investment 

in emission controls. See, e.g., Sen. Rep. No. 91-1196 at 15-16, 

1970 CAA Legis. Hist. at 416 (“[t]he overriding purpose of this 

section [concerning new source performance standards] would be 

to prevent new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of their 

construction is seen by the committee as the most effective and, 

in the long run, the least expensive approach.”); see also 1977 

CAA Amendments, § 109, 91 Stat. at 700, (redefining, with 

respect to new sources, CAA section 111(a)(1) to reflect the 

best “technological system of continuous emission reduction” and 

adding CAA section 111(a)(7) to define this new term). However, 

as a result of the 1990 revisions to CAA section 111(a)(1), new 

Formatted: Highlight

Formatted: Highlight
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However, it is not and never has been used to regulate existing 

sources. In this manner, the 1990 CAA Amendments further 

reinforce the breadth and flexibility of the phrase “system of 

emission reduction,” particularly as it applies to existing 

sources under CAA section 111(d). 

For these reasons, the 1970, 1977, and 1990 legislative 

histories support the EPA’s interpretation in this rule that the 

term is sufficiently broad to encompass building blocks 2 and 3. 

(ii) Reliance on actions taken by other entities. 

The legislative history supports the EPA’s interpretation 

of “system of emission reduction” in another way, as well: The 

legislative history makes clear that Congress intended that 

standards of performance for electric power plants could be 

based on measures implemented by other entities, for example, 

entities that “wash,” or desulfurize, coal (or, for oil-fired 

EGUs, that desulfurize oil). This legislative history is 

consistent with the EPA’s view that the “system of emission 

reduction” may include actions taken by an entity with whom the 

owner/operator of the affected source enters into a contractual 

relationship as long as those actions allow the affected source 

 

source standards would not be restricted to technological 

control measures. 
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to meet its emission limitation. By the same token, this 

legislative history directly refutes commenters’ assertions that 

the phrase “system of emission reduction” must not include 

actions taken by entities other than the affected sources.426

As noted above, in the 1977 CAA Amendments, Congress 

revised the basis for standards of performance for new fossil 

fuel-fired stationary sources to be a “technological system of 

continuous emission reduction,” including “precombustion 

cleaning or treatment of fuels.”427 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 

 

426 See, e.g., comments by UARG at 31 (the building blocks other 

than building block 1 take a “‘beyond-the-source’ approach” and 

“impermissibly rely on measures that go beyond the boundaries of 

individual affected EGUs and that are not within the control of 

individual EGU owners and operators”); comments by American 

Chemistry Council et al. (“Associations”) at 60-61 (EPA’s 

proposed BSER analysis is unlawful because it “looks beyond the 

fence line of the fossil fuel-fired EGUs that are the subject of 

this rulemaking;” “the standard of performance must ... be 

limited to the types of actions that can be implemented directly 

by an existing source within [the appropriate] class or 

category.”). 

427 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA 

section 111(a)(7). 
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and, in revising CAA section 111(a)(1), wanted to ensure that 

such techniques would not be overlooked. For example, the 1977 

House Committee report indicates that an assessment of the best 

technological system of continuous emission reduction for fossil 

fuel-fired power plants would include off-site or third-party 

pre-combustion techniques for reducing emissions at the source 

(“e.g., various coal-cleaning technologies such as solvent 

refining, oil desulfurization at the refinery”).428 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’ 

 

428 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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definition of “standard of performance.” Nevertheless, there is 

no indication that in doing so, Congress intended to preclude 

the EPA from considering coal cleaning by third parties (which 

had been considered within the scope of the best system of 

emission reduction even under the 1970 CAA Amendments),429 and 

in fact, the EPA’s regulations promulgated after the 1990 CAA 

Amendments continue to impose standards of performance that are 

based on third-party coal cleaning.430

(c) Consistency of a broad interpretation of CAA section 

111 with the overall structure of the CAA. 

Interpreting CAA section 111(d)(1) and (a)(1) to authorize 

the EPA’s consideration of the building block 2 and 3 measures 

is consistent with the overall structure of the CAA, 

particularly as it was amended in 1970, when Congress added CAA 

section 111 in much the same form that it reads today. 

 

429 See U.S. EPA, Background Information for Proposed New-Source 

Performance Standards: Steam Generators, Incinerators, Portland 

Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants, Office 

of Air Programs Tech. Rep. No. APTD-0711, p. 7 (Aug. 1971) 

(indicating the “desirability of setting sulfur dioxide 

standards that would allow the use of low-sulfur fuels as well 

as fuel cleaning, stack-gas cleaning, and equipment 

modifications” (emphasis added)). 

430 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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 In the 1970 CAA Amendments, for the most part, and 

particularly for stationary source provisions, Congress painted 

with broad brush strokes, giving broad authority to the EPA or 

the states. That is, Congress established general requirements 

that were intended to produce stringent results, but gave the 

EPA or the states great discretion in fashioning the types of 

measures to achieve those results. 

For example, under CAA section 109, Congress authorized the 

EPA to promulgate national ambient air quality standards (NAAQS) 

for air pollutants, and Congress established general criteria 

and procedural requirements, but left to the EPA discretion to 

identify the air pollutants and select the standards. Under CAA 

section 110, Congress required the states to submit to the EPA 

state implementation plans (SIPs), required that the plans 

attain the NAAQS by a date certain, and established procedural 

requirements, but allowed the states broad discretion in 

determining the substantive requirements of the SIPs. 

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. 
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Under CAA section 112, Congress required the EPA to 

regulate certain air pollutants and to set “emission standards” 

that meet general criteria, and established procedural 

requirements, but did not include other substantive requirements 

and instead, gave the EPA broad discretion in identifying the 

types of pollutants and in determining the standards.431 By and 

large, Congress left these provisions intact in the 1977 CAA 

Amendments.432,433

Congress drafted the CAA section 111(d) requirements in the 

1970 CAA Amendments, and revised them in the 1977 CAA 

 

431 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. 

432 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. 

433 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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Amendments, in a manner that is similar to the other stationary 

source requirements, just described, in CAA sections 109, 110, 

111(b), and 112. The CAA section 111(d) requirements are broadly 

phrased, include procedural requirements, no more than very 

general substantive requirements, and give broad discretion to 

the EPA to determine the basis for the required emission limits 

and to the states to set the standards. It should be noted that 

this drafting approach is not unique to the CAA; on the 

contrary, Congress "usually does not legislate by specifying 

examples, but by identifying broad and general principles that 

must be applied to particular factual instances."434 

In light of this statutory framework, it is clear that 

Congress delegated the EPA with the authority to administer CAA 

section 111, including by authorizing the EPA to apply the 

“broad and general principles” contained in CAA section 

111(a)(1) to the particular circumstances we face today. 

(3) Comments and responses. 

Some 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 

 

434 Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 

(1989) (Kennedy, J., concurring). 
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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(d)(1) and (a)(1), the existing sources subject to the 

standards of performance must be able to achieve their emission 

limit, but that they are able to do so only through measures 

integrated into the source’s own design and operation. As a 

result, according to these commenters, those are the only types 

of measures that may qualify as a “system of emission reduction” 

that may form the basis of the emissions standards. We disagree. 

We see nothing in CAA section 111(d)(1) or (a)(1) which by its 

terms limits CAA section 111 to measures that must be integrated 

into the sources’ own design or operation. Rather, we recognize 

that in order for an emission limitation based on the BSER to be 

“achievable,” the BSER must consist of measures that can be 

undertaken by an affected source -- that is, its owner or 

operator. As noted elsewhere in the preamble, the affected 

sources subject to this rule are fully able to meet their 
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emission standards by undertaking the measures described in all 

the building blocks, including 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 an affected 

source. The most notable comparison is at CAA section 111(a)(7). 

The term “technological system of continuous emission 

reduction,” which was added in 1977 and remains as a separately 

defined term means, in part, “a technological process for 

production or operation by any source which is inherently lowemitting or nonpolluting.” (Emphasis added.) With respect to 

this portion of the definition (and ignoring the additional 

text, which includes “precombustion cleaning or treatment of 

fuels” and clearly encompasses off-site activities), it could be 

argued that between 1977 and 1990 new source performance 

standards should be restricted to measures that could be 
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integrated into the design or operation of a source. However, 

commenters’ assertion that the BSER must be limited in a similar 

fashion ignores the deliberate change in 1990 to restore the 

broader definition of a standard of performance (i.e., that it 

be based on the BSER and not the TSCER). In any case, the 

narrower scope of CAA section 111(a)(7) was never applicable to 

the regulation of existing sources under CAA section 111(d). 

Several other examples of standard setting in the CAA shed 

light on ways in which Congress has constrained the EPA’s 

review. CAA section 407(b)(2) provides that the EPA base NOx

emission limits for certain types of boilers “on the degree of 

reduction achievable through the retrofit application of the 

best system of continuous emission reduction.” (Emphasis added.) 

Likewise, in determining best available retrofit technology 

under CAA section 169A, the state (or Administrator) must “take 

into consideration the costs of compliance, the energy and 

nonair quality environmental impacts, any existing pollution 

control technology in use at the source, the remaining useful 

life of the source, and the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of 
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such technology.”435 (Emphasis added.) These provisions make 

clear that Congress knew how to constrain the basis for emission 

limits to measures that are integrated into the design or 

operation of the affected source, and that its choice to base 

CAA section 111(d)(1) and (a)(1) standards of performance on a 

“system of emission reduction” indicates Congress’ intent to 

authorize a broader basis for those standards. 

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. This argument is unpersuasive for 

several reasons. First, it would be unreasonable to presume that 

Congress intended to limit the BSER, indirectly through these 

other provisions, to measures that are integrated into the 

affected source’s design or operations, when Congress could have 

done so expressly, as it did for the above-discussed Title IV NOx

requirements. 

 

435 Even under BART, the EPA is authorized to allow emissions 

trading between sources. See, e.g., 40 C.F.R. § 51.308(e)(1) & 

(2); Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 (D.C. 

Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 

2005); and Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th 

Cir. 1993). 
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Second, the interpretations that commenters offer for these 

various provisions misapply the text. For example, commenters 

note that under CAA section 111(d)(1), (a)(3), and (a)(6), the 

standards of performance apply to “any existing source,” and an 

“existing source” is defined to include “any stationary source,” 

which, in turn, is defined as “any building, structure, 

facility, or installation which emits or may emit any air 

pollutant.” Commenters assert that these applicability and 

definitional provisions indicate that the BSER provisions in CAA 

section 111(d)(1) and (a)(1) must be interpreted to require that 

the control measures must be integrated into the design or 

operations of the source itself. 

We disagree. These applicability and definitional 

provisions are jurisdictional in nature. Their purpose is simply 

to identify the types of sources whose emissions are to be 

addressed under CAA section 111(d), i.e., stationary sources, as 

opposed to other types of sources, e.g., mobile sources, whose 

are addressed under other CAA provisions (such as CAA Title II). 

This purpose is made apparent by the terms of CAA section 

111(a)(3), which contains two sentences (the second of which 

commenters seem to ignore). The first sentence provides, “The 

term ‘stationary source’ means any building, structure, 
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facility, or installation which emits or may emit any air 

pollutant.” The second sentence provides, “Nothing in subchapter 

II of this chapter relating to nonroad engines shall be 

construed to apply to stationary internal combustion engines.” 

This second sentence explains that stationary internal 

combustion engines are to be regulated under CAA section 111, 

and not Title II (relating to mobile sources), which confirms 

that the purpose of the definition of stationary source is 

jurisdictional in nature -- to identify the emissions that are 

to be regulated under section 111, as opposed to other CAA 

provisions. 

These applicability and definitional provisions say nothing 

about the system of emission reduction –- whether it is limited 

to measures integrated into the design or operation of the 

source itself or may be broader -- that may form the basis of 

the standards for those emissions that are to be promulgated 

under CAA section 111. 

Third, this argument by commenters does not account for the 

commonsense proposition that it is the owner/operator of the 

stationary source, not the source itself, who is responsible for 

taking actions to achieve the emission rate, so that actions 

that the owner/operator is able to take should be considered in 
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determining the appropriate standards for the source’s 

emissions. Buildings, structures, facilities, and installations 

can take no actions -- only owners and operators can install and 

maintain pollution control equipment; only owners and operators 

can solicit precombustion cleaning or treatment of fuel 

services; and only owners and operators can apply for a permit 

or trade allowances. 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.”436 The same is necessarily true for 

existing sources. This supports the EPA’s view that the basis 

for whether a control measure qualifies as a “system of emission 

reduction” 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 

 

436 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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standard[s]” (together, “design standards”) only when a source’s 

emissions are not emitted through a conveyance or cannot be 

measured, makes clear that CAA section 111 standards of 

performance must be based on measures integrated into a source’s 

own design or operations. We disagree. CAA section 111(h) 

concerns the relatively rare situation in which an emission 

standard, which entails a numerical limit on emissions, is not

appropriate because emissions cannot be measured, due either to 

the nature of the pollutant (i.e., the pollutant is not emitted 

through a conveyance) or the nature of the source category 

(i.e., the source category is not able to conduct measurements). 

CAA section 111(h) provides that imposing a design standard is 

appropriate under those circumstances, but only under those 

circumstances. When an emissions standard is appropriate, 

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. 
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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 the fact that Congress did not 

explicitly include these measures in the BSER provisions of CAA 

section 111(d)(1) and (a)(1) indicates that Congress did not 

intend that they be included as part of the BSER, and instead 

intended that the BSER be limited to measures integrated into 

the sources’ design or operations. This argument misses the 

mark. The provisions of CAA section 111(d)(1) and (a)(1) do not 

explicitly include any specific emission reduction measures –- 

neither renewable energy measures (like the ones Congress wanted 

to incentivize under Title IV), nor measures that are integrated 

into the sources’ design or operations (like the retrofit 

control measures Congress required under CAA section 407(b)). 

But this contrast with other CAA provisions does not mean that 
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Congress did not intend the BSER to include any of those types 

of measures. Rather, this contrast supports viewing a “system of 

emission reduction” under CAA section 111 as sufficiently broad 

to encompass a wide range of measures for the purpose of 

emission reduction of a wide range of pollutants from a wide 

range of stationary sources.437

c. Chevron step 2 deference to interpret the BSER to include 

building blocks 2 and 3. Under the familiar Chevron step 2 

analysis, to the extent that it is not clear whether the phrase 

“system of emission reduction” may include the measures in 

building blocks 2 and 3, the EPA’s interpretation of CAA 

section 111(d) and (a) is reasonable438 in light of our 

discretion to determine “whether and how to regulate carbondioxide emissions from power plants....”439 

 

437 It should also be noted that Title IV is limited to 

particular pollutants (i.e., SO2 and NOx) and particular sources 

-– fossil fuel-fired EGUs –- and as a result, lends itself to 

greater specificity about the types of control measures. Section 

111(d), in contrast, applies to a wide range of source types, 

which, as discussed above, supports reading it to authorize a 

broad range of control measures. 

438 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 1603 

(2014) (“We routinely accord dispositive effect to an agency’s 

reasonable interpretation of ambiguous statutory language.”). 

439 American Electric Power v. Connecticut, 131 S. Ct. 2527, 2538 

(2011) (“AEP”) (emphasis added). 
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 Our interpretation that a “system of emission reduction” 

for the affected EGUs may include building blocks 2 and 3 is a 

reasonable construction of the statute for the reasons described 

above and in this section below. 

(1) Consistency of building blocks 2 and 3 with the 

structure of the utility power sector. 

(a) Integration of the utility power sector. 

Certain characteristics of the utility power sector are of 

central importance for understanding why the measures of 

building blocks 2 and 3 qualify as part of the system of 

emission reduction. As discussed above, electricity is highly 

substitutable and the utility power sector is highly integrated, 

so much so that it has been likened to a big machine. 

Specifically, the utility power sector is characterized by a 

physical, as well as operational, interconnection between 

electricity generators themselves, and between those generators 

and electricity users. Because of the physical properties of 

electricity and the current low availability of large scale 

electricity storage, generation and load (or use) must be 

instantaneously balanced in real time. As a result, the utility 

power sector is uniquely characterized by extensive planning and 

highly coordinated operation. These features have been present 
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for decades, and in fact, over time, the sector has become more 

highly integrated. Another important characteristics of the 

utility power sector is that although the states have developed 

both regulated and de-regulated markets, the generation of 

electricity reflects a least-cost dispatch approach, under which 

electricity is generated first by the generators with the lowest 

variable cost. 

These characteristics of the sector have facilitated the 

overall objective of providing reliable electric service at 

least cost subject to a variety of constraints, including 

environmental constraints. Moreover, in each type of market, the 

sector has developed mechanisms, including the participation of 

institutional actors, to safeguard reliability and to assure 

least cost service. 
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Congress,440 the Courts,441 the EPA in its regulatory 

actions,442 and states in their regulatory actions443 have 

recognized the integrated nature of the utility power sector. 

(b) Significance of integrated utility power sector for the 

BSER. 

The fungibility of electricity, coupled with the 

integration of the utility power sector, means that, assuming 

that demand is held constant, adding electricity to the grid 

from one generator will result in the instantaneous reduction in 

generation from other generators. Similarly, reductions in 

generation from one generator lead to the instantaneous increase 

in generation from other generators. Thus, the operation of 

 

440 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). 

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

at 7 (2002) (citing Brief for Respondent FERC 4-5). 

442 “Stack Heights Emissions Balancing Policy,” 53 Fed. Reg. 480, 

482 (Jan. 7, 1988). 

443 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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individual EGUs is integrated and coordinated with the 

operations of other EGUs and other sources of generation, as 

well as with electricity users. This allows for locational 

flexibility across the sector in meeting demand for electricity 

services. The institutions that coordinate planning and 

operations routinely use this flexibility to meet demand for 

electricity services economically while satisfying constraints, 

including environmental constraints. Because of these 

characteristics, EGU owner/operators have long conducted their 

business, including entering into commercial arrangements with 

third parties, based on the premise that the performance and 

operations of any of their facilities is substantially dependent 

on the performance and operation of other facilities, including 

ones they neither own nor operate. For example, when an EGU goes 

off-line to perform maintenance, its customer base is served by 

other EGUs that increase their generation. Similarly, if an EGU 

needs to assure that it can meet its obligations to supply a 

certain amount of generation, it may enter into arrangements to 

purchase that generation, if it needs to, from other EGUs. 

Because of this structure, fossil fuel-fired EGUs can 

reduce their emissions by taking the actions in building blocks 

2 and 3. Specifically, fossil fuel-fired EGUs may generate or 
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cause the generation of increased amounts of lower- or zeroemitting electricity –- through contractual arrangements, 

investment, or purchase -- which will back out higher-emitting 

generation, and thereby lower emissions. In addition, fossil 

fuel-fired EGUs may reduce their generation, which, given the 

overall emission limits this rule requires, will have the effect 

of stimulating lower- or zero-emitting generation. 

It should also be noted that CO2 is particularly well-suited 

for building blocks 2 and 3 because it is a global, not local, 

air pollutant, so that the location where it is emitted does not 

affect its environmental impact. The U.S. Supreme Court in the 

UARG case highlighted the importance of taking account of the 

unique characteristics of CO2.444

In light of these characteristics of the utility power 

sector, as well as the characteristics of CO2 pollution, it is 

reasonable for the EPA to reject an interpretation of the term 

“system of emission reduction” that would exclude building 

blocks 2 and 3 from consideration in this rule and instead 

restrict consideration to measures integrated into each 

individual affected source’s design or operation, especially 

since the record and other publicly available information makes 

 

444 See UARG v. EPA, 134 S. Ct. 2427, 2441 (2014). 
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abundantly clear how effective the two building blocks are in 

reducing emissions and how widely those measures are already 

being used. 

As discussed above, no such restriction on the measures 

that can be considered part of a “system of emission reduction” 

is required by the statutory language, and the legislative 

history demonstrates that Congress intended a broad 

interpretation of the phrase. The narrow interpretation 

advocated by some commenters would permit consideration only of 

potential CO2 reduction measures that are either more expensive 

than building blocks 2 and 3 (such as the use of natural gas cofiring at affected EGUs or the application of CCS technology) 

or measures capable of achieving far less reduction in CO2

emissions (such as the heat rate improvement measures included 

in building block 1). Imposing such a restrictive interpretation 

–- one which is not even called for by the statute -- would be 

inconsistent with CAA section 111’s specific requirement that 

standards be based on the “best” system of emission reduction 

and, as discussed below, would nullify any serious efforts to Formatted: Highlight
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fulfill the CAA’s overall environmental promise and address the 

most pressing environmental issue of our time.445 

The unique characteristics of the sector described above 

require coordinated action in the fundamental, primary function 

of EGUs – and in meeting current pollution control requirements 

to the extent that EGUs operate in dispatch systems that apply 

variable costs in determining dispatch -- and affected EGUs 

necessarily already plan and operate on a multi-unit basis. In 

doing so, they already make use of building blocks 2 and 3 to 

meet operational and environmental objectives in a costeffective manner, as further described below. CO2 is a global 

pollutant that is exceptionally well-suited to emission 

reduction efforts optimized on a broad geographic scale rather 

than on a unit-by-unit basis. It is also clear from both 

comments and communications received through the Agency’s 

outreach efforts that affected EGUs will seek to use building 

blocks 2 and 3 to achieve compliance with the emission standards 

set in the section 111(d) plans following promulgation of this 

rule. For these reasons –- and the additional reasons discussed 

below -- interpreting “system of emission reduction” so as to 

 

445 See King v. Burwell, No. 14-114 (2015) (slip op., at 21) 

(“But in every case we must respect the role of the Legislature, 

and take care not to undo what it has done.”). 

Formatted: Highlight
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allow consideration in this rule of only the individual pieces 

of the “complex machine,” and to forbid consideration of the 

ways in which the pieces actually fit and work together as parts 

of that machine, such as building blocks 2 and 3, cannot be 

justified. This is particularly so in light of the dilemma 

presented by the types of control options that commenters argue 

are the only ones authorized under section 111(a)(1), which are 

controls that apply to the design or operation of the affected 

EGUs themselves. On the one hand, the control measures in 

building block 1 yield only a small amount of emission 

reductions, and could result in increased overall emissions. On 

the other hand, control measures such as carbon capture and 

storage, or co-firing with natural gas, could yield much greater 

emission reductions, but are substantially more expensive than 

building blocks 2 and 3. 

(2) Current implementation of measures in building blocks 2 

and 3. 

The requirement that the “system of emission reduction” be 

“adequately demonstrated” suggests that we begin our review 

under CAA section 111(d)(1) and (a)(1) with the systems that 

sources are already implementing to reduce their emissions. As 

noted above, fossil fuel-fired EGUs have long implemented, and 

Deleted: .
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are continuing to implement, the measures in building blocks 2 

and 3 for various purposes, including for the purpose of 

reducing CO2 emissions446 – and certainly always with the effect 

of reducing emissions. This is a strong indicator that these 

measures should be considered part of a “system of emission 

reduction” for CO2 emissions from these sources. The requirement 

that the “system of emission reduction” be “adequately 

demonstrated” indicates that the implementation of control 

mechanisms or other actions that the sources are already taking 

to reduce their emissions are of particular relevance in 

establishing the emission reduction requirements of CAA section 

111(d)(1) and (a)(1). As a result, such measures are a logical 

starting point for consideration as a “system of emission 

reduction” under CAA section 111. 

(3) Reliance in CAA Title IV on building block measures. 

 

446 A number of utilities have climate mitigation plans. Examples 

include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 
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Some of the building block approaches to reducing emissions 

in the utility power sector were first tested around the time 

that Congress adopted the 1970 CAA Amendments.447 Over time, 

these techniques have become more established within the 

industry, and by the 1990 CAA Amendments, Congress even based 

the Title IV acid rain program for existing fossil fuel-fired 

EGUs in part on the same measures that are considered here. This 

provides an important indication that Congress not only viewed 

such measures as effective emission control techniques but that 

these same measures had been implemented by the industry for at 

least twenty years. 

(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 

 

447 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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provision to examine for this purpose is Title IV, which 

includes a nationwide cap-and-trade program under which coalfired power plants must have allowances for their sulfur dioxide 

emissions. 

Title IV includes several signals that it is especially 

relevant for interpreting and implementing CAA section 111(d) 

for purposes of this rule. Title IV applies to most of the same 

sources that this rule applies to -- existing coal-fired EGUs 

and other utility boilers, as well as NGCC units. In addition, 

Congress added Title IV in the 1990 CAA Amendments at the same 

time that Congress largely reinstated the 1970-vintage reading 

of section 111(a)(1) to adopt the currently applicable 

definition of a “standard of performance,” which is based on the 

“best system of emission reduction ... adequately demonstrated.” 

Moreover, Congress linked Title IV and CAA section 111 in 

certain respects. Specifically, Congress conditioned the 

revisions to CAA section 111(a)(1), i.e., eliminating the 

percentage reduction and most of the other limitations under the 

1977 CAA Amendments, on the continued applicability of the Title 

IV SO2 cap, so that if the cap were eliminated, the changes 

would, by operation of law, also be eliminated, and the 1977 
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version of section 111(a)(1) would be reinstated.448

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.449 While 

industrial sources were not required to participate under Title 

IV -- they could elect to do so, under CAA section 410(a) -- 

Congress believed SO2 reductions from these sources were “an 

essential component of the reductions sought under [Title IV]” 

and intended that Title IV would “assure[] that these projected 

reductions occur and will not be overcome by future growth in 

emissions.”450 As such, Congress viewed federal standards of 

 

448 1990 CAA Amendments, § 403, 104 Stat. at 2631 (requiring 

repeal of amendments to CAA section 111(a)(1) upon any cessation 

of effectiveness of CAA section 403(e), which requires new units 

to hold allowances for each ton of sulfur dioxide emitted). 

Congress believed that mandating a technological standard 

through the percentage reduction requirement in 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. 

449 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). 450 Sen. Rep. No. 101-228, at 345 (Dec. 20, 1989). 
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performance as the appropriate backstop to Title IV even for 

sources that could not otherwise be regulated under CAA section 

111(d).451 Together, these signals suggest that it is reasonable 

for the EPA to consider Title IV when interpreting and 

implementing CAA section 111. 

For present purposes, the essential features of Title IV 

are that it regulates SO2 emissions from coal-fired EGUs by 

adopting a nationwide cap of 8.95 million tons to be achieved 

through a tradable allowance system. As we explain below, the 

provisions of Title IV and its legislative history make clear 

that Congress based the stringency of the emission limitation 

requirement (8.95 million tons) and the overall structure of the 

approach (a cap-and-trade system) on Congress’s recognition that 

the affected EGUs had a set of tools available to them to reduce 

their emissions, including through a shift to lower emitting 

generation and use of 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 

 

451 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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serving as part of the “system of emission reduction” that is 

the EPA’s basis for the section 111(d) emission guidelines. For 

this reason, the fact that in Title IV, Congress relied on 

generation shift and renewable energy as the basis for the SO2

emission limitations for affected EGUs strongly supports 

interpreting CAA section 111(d)(1) and (a)(1) to include use of 

those same measures as part of the “system of emission 

reduction” as the basis for CO2 emission limitations for those 

same sources. 

(b) Title IV provisions. 

Several provisions of Title IV make explicit Congress’s 

reliance on some of the same measures as are in building blocks 

2 and 3. Title IV begins with a statement of congressional 

“findings,” including the following: 

§401(a). Findings 

The Congress finds that – 

* * * * 

(4) strategies and technologies for the control of 

precursors to acid deposition exist now that are 

economically feasible, and improved methods are 

expected to become increasingly available over the 

next decade. 

(Emphasis added.) Title IV then includes the following statement 

of its “purposes:” 
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§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”452 would encourage such “technologies and 

strategies” as 

energy efficiency; enhanced emissions reduction or 

control technologies—like sorbent injection, cofiring 

with natural gas, integrated gasification combined 

cycles; fuel-switching and least-emissions dispatching

in order to maximize emissions reductions.”453 

 

452 See Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989). 453 See Sen. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 

added). 
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Congress’s reliance on generation shifting and renewable energy 

to reduce acid rain precursors from affected EGUs in Title IV 

strongly supports the EPA’s authority to identify those same 

measures as part of the CAA section 111 “system of emission 

reduction” to reduce CO2 emissions from those same sources. 

 In addition, Title IV includes other provisions expressly 

concerning renewable energy. In CAA section 404(f) and (g), 

Congress set aside a special pool of allowances to encourage use 

of renewable energy. In order to obtain a special allowance 

(which would authorize emissions from a coal-fired utility), an 

electric utility needed to pay for qualifying renewable energy 

sources “directly or through purchase from another person.”454

These measures confirm Congress’s recognition that renewable 

energy was available to the industry, was desirable to encourage 

from a policy perspective, and was appropriate to consider in 

determining the amount of pollution reduction the law should 

require. 

(c) Title IV legislative history. 

Numerous statements in the legislative history confirm that 

Congress based the Title IV requirements on the fact that 

affected EGUs could reduce their SO2 emissions through a set of 

 

454 CAA section 404(f)(2)(B)(i). 
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measures, including shifting to lower-emitting generation as 

well as reliance on renewable energy. 

For example, the Senate Committee Report455 and Senator 

Baucus,456 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.457 

 

455 Sen. Rep. to accompany S. 1630, Sen. Rep. 101-228 (Dec. 20, 

1989), 1990 CAA Legis. Hist. at 8656 

456 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). 

457 H.R. Rep. No. 101-490, pp. 368-69; 674-76 (May 17, 1990) 

(additional views of Reps. Markey and Moorhead) (“We believe 

that H.R. 3030, as amended, will create a strong and effective 

incentive for utilities to immediately pursue energy 

conservation and renewable energy sources as key components of 

their acid rain control strategies.”); see also Rep. Collins, H. 

Debates on H.R. Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA 

Legis. Hist. at 1307 (“The bottom line is that our Nation's 

utilities and production facilities must reach beyond coal, oil, 

and fossil fuels. The focus must shift instead toward 
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 (4) Reliance on renewable energy measures to reduce carbon 

dioxide. 

The Title IV legislative history also makes clear that 

Congress viewed renewable energy measures as a means to reduce 

carbon dioxide for the purpose of mitigating climate change. By 

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.458 The 

record for the 1970 CAA Amendments include hearings459 and a 

 

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.”). 

458 “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.”). 

459 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381 (stating that “the carbon dioxide balance might result 

in the heating up of the atmosphere whereas the reduction of the 

radiant energy through particulate matter released to the 
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report by the National Academy of Sciences noting that carbon 

dioxide emissions could heat the atmosphere.460 A 1976 report 

noting the phenomenon was included in the record for the 1977 

CAA Amendments.461 A 1977 Report by the National Academy of 

Sciences warned that average temperatures would rise due to the 

burning of fossil fuel.462 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. 

 

atmosphere might cause reduction in radiation that reaches the 

earth”). 

460 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.”). 

461 122 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”). 

462 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). 
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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.463 

 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....”464 In addition, 

 

463 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

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. 

464 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 

Legis. Hist. at 7106. 
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the 1990 CAA Amendments required EGUs covered by the monitoring 

requirements of the Title IV acid rain program to report their 

CO2 emissions.465 

(5) Other EPA actions that rely on the building block 

measures. 

Another indication that it is reasonable to interpret the 

CAA section 111(d)(1) and (a)(1) provisions for the BSER to 

include the measures in building blocks 2 and 3 is that the EPA 

and states have relied on these measures to reduce emissions in 

a number of other CAA actions. 

For example, in 2005, the EPA promulgated a rule to control 

mercury emissions from fossil fuel-fired power plants under 

section 111(d): the Clean Air Mercury Rule (CAMR).466 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 

 

465 1990 CAA Amendments, § 821, 104 Stat. at 2699. 466 70 FR 28606 (May 18, 2005). 
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generation to lower-emitting units.467 CAMR was vacated by the 

D.C. Circuit on other grounds,468 but it shows that in the only 

other section 111(d) rule that the EPA attempted for affected 

EGUs, the EPA relied on shifting generation as part of the BSER 

in a CAA section 111(d) rulemaking for fossil fuel-fired EGUs. 

In 2011, the EPA promulgated the Cross State Air Pollution 

Rule (CSAPR),469 in which it set statewide emission budgets for 

NOx and SO2 emitted by fossil fuel-fired EGUs, and based those 

standards in part on shifts to lower-emitting generation. CSAPR 

established state-wide emissions budgets based on a range of 

cost-effective actions that EGUs could take, and set the 

stringency of the deadlines for some required reductions in part 

because of the availability of “increased dispatch of loweremitting generation which can be achieved by 2012.”470 The EPA 

developed a federal implementation plan (FIP) that established a 

 

467 70 FR 28606, 28619 (May 18, 2005) (“Under the CAMR scenario 

modeled by EPA, units [were] projected to meet their SO2 and NOx

requirements and take additional steps to address the remaining 

[mercury] reduction requirements under CAA section 111, 

including adding [mercury]-specific control technologies (model 

applies [activated carbon injection]), additional scrubbers and 

[selective catalytic reduction], dispatch changes, and coal 

switching.”). 

468 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). 

469 76 Fed. Reg. 48208 (Aug. 8, 2011). 470 76 Fed. Reg. at 48452. 

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trading program to meet the state-wide emission budgets set by 

CSAPR. The EPA projected that sources would meet their emission 

reduction obligations by implementing a range of emission 

control approaches, including the operation of add-on controls, 

switches to lower-emitting coal, and “changes in dispatch and 

generation shifting from higher emitting units to lower emitting 

units.”471 The U.S. Supreme Court upheld CSAPR in EPA v. EME 

Homer City Generation, L.P.472

 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.473 Some 

 

471 76 FR at 48279-80. The exact mix of controls varied for 

different air pollutants and different time periods, but in all 

cases, shifting generation from higher to lower emitting units 

was one of the expected control strategies for the fossil fuelfired power plants. Prior to CSAPR, the EPA promulgated two 

other transport rules, the NOx SIP Call (1998) and the Clean Air 

Interstate Rule (CAIR) (2005), which similarly established 

standards based on analysis of the availability and cost of 

emission reductions achievable through the use of add-on 

controls and generation shifting, and also authorized and 

encouraged the implementation of 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). 

472 134 S. Ct. 1584 (2014). 473See, e.g., Guidance on SIP Credits for Emission Reductions 

from Electric-Sector Energy Efficiency and Renewable Energy 
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states have done so. For example, Connecticut included in its 

SIP reductions from solar photovoltaic installations.474 In 2012, 

the EPA provided additional guidance on this topic.475 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.476

(6) Other rules that relied on actions by other entities. 

 

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. 474 CT 1997 8-hour ozone SIP Web site, 

http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1619 (see 

Attainment Demonstration TSD, Chapter 8 at 31, 

http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_reports/s

ection_8.pdf). 475 “Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs” (July 2012), 

http://epa.gov/airquality/eere/manual.html.

476 States’ Perspectives on EPA’s Roadmap to Incorporate Energy 

Efficiency/Renewable Energy in NAAQS State Implementation Plans: 

Three Case Studies, Final Report to the U.S. Environmental 

Protection Agency (Dec. 2013), 

http://www.nescaum.org/documents/nescaum-final-rept-toepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf. 

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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 trading of mass-based emission allowances or rate-based 

emission credits, in which many sources meet their emission 

limitation requirements by purchasing allowances or credits from 

other sources that reduce emissions. 

(a) Third-party transactions. 

To reiterate, commenters argue that the “system of emission 

reduction” must be limited to measures taken by the affected 

source itself because only those measures are under the control 

of the affected source, as opposed to third parties, and 

therefore only those measures can assure that the affected 

source will achieve its emission limits. But this argument is 

belied by the fact that for a wide range of pollution control 

measures – including many that are indisputably part of a 
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“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 install the 

controls needed by the affected EGUs.477 In addition, EGU owners 

and operators may be dependent on the actions of third parties 

to finance the controls and third-party regulators to assure the 

mechanism for repaying that financing. However, this dependence 

does not mean that the emission limit based on that equipment is 

not achievable. Rather, the fact that the owner or operator of 

the affected source can arrange with the various third parties 

to acquire, install, and pay for the equipment means that 

emission limit is achievable. 

 

477 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 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 

in as part of their normal course of business, which include, 

among many examples, transactions with RTOs/ISOs or balancing 

authorities, entities in organized markets. 

(b) Emissions trading. 

Additional precedent that the “system of emission 

reduction” may include the measures in building blocks 2 and 3 

and is not limited to measures that a source can integrate into 

its own design or operations, without being dependent on other 

entities, is found in the many rules that Congress has enacted 

or that the EPA has promulgated that allow EGUs and other 

sources to meet their emission limits by trading with other 

sources. In a trading rule, the EPA authorizes a source to meet 
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its emission limit by purchasing mass-based emission allowances 

or rate-based emission credits generated from other sources, 

typically ones that implement controls that reduce their 

emissions to the point where they are able to sell allowances or 

credits. As a result, the availability of trading reduces 

overall costs to the industry by focusing the controls on the 

particular sources that have the least cost to implement 

controls. For present purposes, what is relevant is that in a 

trading program, some affected sources choose to meet their 

emission limits not by implementing emission controls integrated 

into their own design or operations, but rather by purchasing 

allowances or credits. These affected sources, therefore, are 

dependent on the actions of other entities, which are the ones 

that choose to deploy clean energy technologies such as 

renewables or meet their emission limits by implementing 

emission controls, which permits them to sell allowances or 

credits. They are “dependent”, however, in exactly the same way 

that a source acquiring pollution control technology for the 

purposes of meeting a NSPS is “dependent” on a vendor of that 

technology to fulfill its contractual obligations. Just so for 

the source operator purchasing a credit or an allowance. In 

essence, the purchasing operator is acquiring an equity in the 
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technology or action applied to the credit-selling source for 

purposes of achieving a reduction in emissions occurring at the 

selling source. Trading programs have been commonplace under the 

CAA, particularly for EGUs, for decades. They include the acid 

rain trading program in Title IV of the CAA, the trading 

programs in the transport rules promulgated by the EPA under the 

“good neighbor provision” of CAA section 110(a)(2)(D)(i)(I), the 

Clean Air Mercury Rule, and the regional haze rules. In each of 

these actions, the Congress or the EPA recognized that some of 

the affected EGUs would implement controls or take other actions 

that would lower their emissions and thereby allow them to sell 

allowances to other EGUs, which were dependent on the purchase 

of those allowances to meet their obligations.478 For the reasons 

 

478 For example, in the enacting the acid rain program under CAA 

Title IV, Congress explicitly recognized that some sources would 

comply by purchasing allowances instead of implementing 

controls. Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989). 

Similarly, in promulgating the NOx SIP Call in 1998, the EPA 

stated, “Since EPA's determination for the core group of sources 

is based on the adoption of a broad-based trading program, 

average cost-effectiveness serves as an adequate measure across 

sources because sources with high marginal costs will be able to 

take advantage of this program to lower their costs.” 63 FR at 

57399 (emphasis added). By the same token, in promulgating the 

Cross State Air Pollution Rule, the EPA stated, “the preferred 

trading remedy will allow source owners to choose among several 

compliance options to achieve required emission reductions in 

the most cost effective manner, such as installing controls, 

changing fuels, reducing utilization, buying allowances, or any 
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just described, these trading rules refute commenters’ arguments 

for limiting the scope of the “system of emission reduction.” 

 

(c) NSPS rules for EGUs that depend on the integrated grid. 

The EPA has promulgated NSPS for EGUs that include requirements 

based on the fact that an EGU may reduce its generation, and 

therefore its emissions, because the integration of the grid 

allows another EGU to increase generation and thereby avoid 

jeopardizing the supply of electricity. For example, in 1979, 

the EPA finalized new standards of performance to limit 

emissions of SO2 from new, modified, and reconstructed EGUs. In 

evaluating the best system against concerns of electric service 

reliability, the EPA took into account the unique features of 

power transmission along the interconnected grid and the unique 

commercial relationships that rely on those features.479

 

combination of these actions.” 76 Fed. Reg. at 48272 (emphasis 

added). 

479 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 
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Additionally, in 1982, the EPA recognized that utility turbines 

could meet a NOx emission limit without unacceptable economic 

consequences because “other electric generators on the grid can 

restore lost capacity caused by turbine down time.”480 We 

describe the relevant parts of these rules in greater detail in 

the Legal Memorandum. 

(7) Consistency with the purposes of the Clean Air Act. 

Interpreting the term “system of emission reduction” 

broadly to include building blocks 2 and 3 (so that the “best 

system of emission reduction ... adequately demonstrated” may 

include those measures as long as they meet all of the 

applicable requirements) is also consistent with the purposes of 

the CAA. Most importantly, these purposes include protecting 

public health and welfare by comprehensively addressing air 

pollution, and, particularly, protecting against urgent and 

severe threats. In addition, these purposes include promoting 

pollution prevention measures, as well as the advancement of 

systems of emission reduction. 

 

480 47 FR 3767, 3768 (Jan. 27, 1982). 

Deleted: technology that reduces air pollution. 
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(a) Purpose of protecting public health and welfare 

The first provisions in the Clean Air Act set out Congress’s 

findings and the CAA’s purposes. They provide as follows, in 

relevant part: 

Section 101. Congressional findings and declaration of 

purpose 

(a) The Congress finds— 

* * * * 

(2) that the growth in the amount and complexity of 

air pollution brought about by urbanization, 

industrial development, and the increasing use of 

motor vehicles, has resulted in mounting dangers to 

the public health and welfare * * * * 

(3) that air pollution prevention (that is, the 

reduction or elimination, through any measures, of the 

amount of pollutants produced or created at the 

source) and air pollution control at its source is the 

primary responsibility of States and local 

governments; and 

(4) that Federal financial assistance and leadership 

is essential for the development of cooperative 

Federal, State, regional, and local programs to 

prevent and control air pollution. 

(b) The purposes of this title are— 

(1) to protect and enhance the quality of the Nation’s 

air resources so as to promote the public health and 

welfare and the productive capacity of its population; 

(2) to initiate and accelerate a national research and 

development program to achieve the prevention and 

control of air pollution; 
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(3) to provide technical and financial assistance to 

State and local governments in connection with the 

development and execution of their air pollution 

prevention and control programs; and 

(4) to encourage and assist the development and 

operation of regional air pollution prevention and 

control programs. 

(c) POLLUTION PREVENTION.—A primary goal of this Act 

is to encourage or otherwise promote reasonable 

Federal, State, and local governmental actions, 

consistent with the provisions of this Act, for 

pollution prevention. 

As just quoted, these provisions are explicit that the 

purpose of the CAA is “to protect and enhance the quality of the 

Nation’s air resources so as to promote the public health and 

welfare and the productive capacity of its population.” 

Moreover, Congress designed the CAA to be “the comprehensive 

vehicle for protection of the Nation’s health from air 

pollution,”481 and, in fact, designed CAA section 111(d) to 

address air pollutants not covered under other provisions, 

specifically so that “there should be no gaps in control 

activities pertaining to stationary source emissions that pose 

 

481 H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2509 (discussing a provision in the House Committee 

bill that became CAA section 122, requiring the EPA to study and 

regulate radioactive air pollutants and three other air 

pollutants). 
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any significant danger to public health or welfare.”482

Furthermore, in these purpose provisions, Congress recognized 

that while pollution prevention and control are the primary 

responsibility of the States, “federal leadership” would be 

essential. 

At its core, Congress designed the CAA to address urgent 

and severe threats to public health and welfare. This purpose is 

evident throughout 1970 CAA Amendments, which authorized 

stringent remedies that were necessary to address those 

problems. Congress viewed the air pollution problem in 1970 as a 

crisis,483 and enacted a stringent response, designed to match 

 

482 Sen. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420 (discussing section 114 of the Senate 

Committee bill, which was the basis for CAA section 111(d)).

483 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. 
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the severity of the problem. At the same time, Congress did not 

foreclose the EPA’s ability to address new environmental 

concerns; in fact, Congress largely deferred to the EPA’s 

expertise in identifying pollutants and sources that adversely 

affect public health or welfare. In doing so, Congress 

authorized the EPA to establish ambient air quality standards to 

protect public health with an ample margin of safety, and 

required states to develop plans to assure that their air 

quality areas would meet those standards by no later than five 

years. Congress also required the EPA to establish standards for 

hazardous air pollutants that could result in shutting sources 

down. Congress added stringent controls on automobiles, 

overriding industry objections that the standards were not 

achievable. In addition, Congress added CAA section 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 

 

“[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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stationary source emissions that pose any significant danger to 

public health or welfare.”484 

Similarly, the 1977 and 1990 CAA Amendments were also 

designed to respond to new and/or pressing environmental issues. 

For example, in 1977 then-EPA Administrator Costle testified 

before Congress that the expected increase in coal use (in 

response to various energy crises, including the 1973-74 Arab 

Oil Embargo) “will make vigorous and effective control even more 

urgent.”485 Similarly, by 1990, Congress recognized that “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”486 Indeed, President 

 

484 Sen. Rep. No. 91-1196, p. 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420 (discussing section 114 of the Senate 

Committee bill, which was the basis for CAA section 111(d)). 

Note that in the 1977 CAA Amendments, the House Committee Report 

made a similar statement. H.R. Rep. No. 95-294, at 42 (May 12, 

1977), 1977 CAA Legis. Hist. at 2509 (discussing a provision in 

the House Committee bill that became CAA section 122, requiring 

EPA to study and then take action to regulate radioactive air 

pollutants and three other air pollutants). 

485 Statement of Administrator Costle, Hearings before the 

Subcommittee on Energy Production and Supply of the Senate 

Committee on Energy and Natural Resources (Apr. 5, 7, May 25, 

June 24 and 30, 1977), 1977 CAA Legis. Hist. at 3532 (discussing 

the relationship between the National Energy Plan and the 

Administration’s proposed CAA amendments). Some of the specific 

changes to the CAA include the addition of the PSD program, 

visibility protections, requirements for nonattainment areas, 

and stratospheric ozone provisions. 

486 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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George H. W. Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”487 

Much remains to be done with respect to climate change. We 

are now at a critical juncture to take meaningful action to curb 

the growth in CO2 emissions and forestall the impending 

consequences of inaction. CO2 emissions from existing fossil 

fuel-fired power plants are by far the largest source of 

stationary source emissions. They amount to almost 3 times as 

much of CO2 emissions from the next 9 stationary source 

categories combined, and approximately equal the amount of CO2

emissions from all of the nation’s mobile sources. At present, 

however, no add-on controls are commercially available that will 

make anything other than small reductions in power plant CO2 

emissions. The only controls available that can reduce CO2 

emissions from existing power plants in amounts commensurate 

with the problems they pose are the measures in building blocks 

2 and 3. 

 

487 H.R. Rep. No. 101-490, at 144 (May 17, 1990). Some of the 

changes adopted in 1990 include revisions to the NAAQS 

nonattainment program, a more aggressive and substantially 

revised CAA section 112, the new acid rain program, an operating 

permits program, and a program for phasing out of certain ozone 

depleting substances. 
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Thus, interpreting the “system of emission reduction” 

provisions in CAA section 111(d)(1) and (a)(1) to allow the 

nation to meaningfully address the urgent and severe public 

health and welfare threats that climate change pose is 

consistent with what the CAA was designed to do.488 This 

interpretation is also consistent with the cooperative purpose 

of section 111(d) to assure that the CAA comprehensively address 

those threats through the mechanism of state plans, where the 

states assume primary responsibility under federal leadership. 

See King v. Burwell, 576 U.S. (2015), No. 14-114 (2015), slip 

op. at 15 (“We cannot interpret federal statutes to negate their 

own stated purposes” (quoting New York State Dept. of Social 

Servs. v. Dublino, 413 U.S. 405, 419-20 (1973)); id. at 21 (“A 

 

488 In addition, as we have noted, in designing the 1970 CAA 

Amendments, Congress was aware that carbon dioxide increased 

atmospheric temperatures. In 1970, when Congress learned that 

“the carbon dioxide balance might result in the heating up of 

the atmosphere” and that particulate matter “might cause 

reduction in radiation,” the Nixon Administration assured 

Congress that “[w]hat we are trying to do, however, in terms of 

our air pollution effort should have a very salutary effect on 

either of these.” Testimony of Charles Johnson, Jr., 

Administrator of the Consumer Protection and Environmental 

Health Service (Administration Testimony), Hearing of the House 

Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 

CAA Legis. Hist. at 1381. Many years later, scientific consensus 

has formed around the particular causes and effects of climate 

change; and the tools put in place in 1970 can be read fairly to 

address these concerns. 
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fair reading of legislation demands a fair understanding of the 

legislative plan.”).489

 

 (b) Purpose of encouraging pollution prevention. 

Interpreting “system of emission reduction” to include building 

blocks 2 and 3 is also consistent with the CAA’s purpose to 

encourage pollution prevention. CAA section 101(c) states that 

“[a] primary goal of [the CAA] is to encourage or otherwise 

 

489 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. See

H.R. Rep. No. 95-294, at 49 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2516 (describing the CAA as being designed to 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”).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 costeffective measures in those building blocks achieves more 

pollution reduction than building block 1 alone. Indeed, add-on 

controls that are technically capable of reducing CO2 emissions 

at the scale necessitated by the severity of the environmental 

risk -– for example, CCS technology -- are not as cost-effective 

as building blocks 2 and 3 on an industry-wide basis, and while 

the costs of the add-on controls can be expected to be reduced 

over time, it is not consonant with the precautionary spirit of 

the CAA to wait. 

Formatted: Highlight

Formatted: Highlight
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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.”490 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.491 

The measures in building blocks 2 and 3 qualify as 

“pollution prevention” measures because they are “any measures” 

 

490 See Air Quality Act of 1967, Pub. L. 90-148, § 2, 81 Stat. 

485 (Nov. 21, 1967) (adding “Title I—Air Pollution Prevention 

and Control” to the CAA, along with Congress’ initial findings 

and purposes under CAA section 101). 

491 Section 101 emphasizes the importance of air pollution 

prevention in two other provisions: CAA section 101(b)(4) states 

that one of “the purposes of [title I of the CAA, which includes 

section 111] are ... (b) to encourage and assist the development 

and operation of regional air pollution prevention and control 

programs.” CAA section 101(a)(3) adds: “The Congress finds -- 

... (3) that air pollution prevention ... and air pollution 

control at its source is the primary responsibility of states 

and local governments.” In fact, section 101 mentions pollution 

prevention no less than 6 times. 
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that “reduc[e] or eliminate[e] ... the amount of pollutants 

produced or created at the [fossil fuel-fired affected] 

source[s].” Thus, consistent with the CAA’s primary goals, it is 

therefore reasonable to interpret a “system of emission 

reduction,” as including the pollution prevention measures in 

building blocks 2 and 3. 

(c) Purpose of advancing technology to control air 

pollution. 

This final rule is also consistent with the purpose of CAA 

section 111 to promote the advancement of pollution control 

technology, based on the expectation that American industry will 

be able to develop innovative solutions to the environmental 

problems. 

 The legislative history and case law of CAA section 111 

identify three different ways that Congress designed CAA section 

111 to authorize standards of performance that promote 

technological improvement: (i) the development of technology 

that may be treated as the “best system of emission reduction 

... adequately demonstrated;” under CAA section 111(a)(1);492

 

492 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”). 
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(ii) the expanded use of the best demonstrated technology;493 and 

(iii) the development of emerging technology.494 This rule is 

consistent with the second of those ways –- it expands the use 

of the measures in building blocks 2 and 3, which are already 

established and provide substantial reductions at reasonable 

cost. As discussed below, the use of the measures in these 

building blocks will be most fully expanded when organized 

markets develop, and our expectation that those markets will 

develop is consistent with the Congress’s view, just described, 

that CAA section 111 should promote technological innovation. 

This final rule is also consistent with Congress’s overall 

view that the CAA Amendments as a whole were designed to promote 

technological innovation. In enacting the CAA, Congress 

articulated its expectation that American industry would be 

creative and come up with innovative solutions to the urgent and 

severe problem of air pollution. This is manifest in the wellrecognized technology-forcing nature of the CAA, and was 

expressed in numerous, sometimes ringing, statements in the 

 

493 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”). 

494 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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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.495 

(d) Response to commenters concerning purpose. Commenters 

have stated that the proposed rule “would transform CAA section 

111 into something untethered to its statutory language and 

unrecognizable to the Congress that created it.”496 On the 

contrary, we believe that this rule would be recognizable to the 

Congresses that created and amended CAA section 111 and is 

 

495 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 

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.”) 

496 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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carefully fashioned to the statutory text in CAA section 111(d) 

and (a)(1). This final rule would be recognizable to the 

Congress that adopted CAA section 111 in 1970 as part of a 

stringent, comprehensive 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 

(generation shifts and renewable energy), and that explicitly 

acknowledged that those measures (renewable energy) would also 

reduce carbon dioxide and thereby address the dangers of climate 

change. Above all, for the reasons explained in this preamble, 

this rule is grounded in our reasonable interpretation of CAA 

section 111(d) and (a)(1). 
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(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.497 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 3.498

As discussed above, the emission limits in the CAA section 

111(d) emission guidelines that this rule promulgates are based 

on the EPA’s determination, for the affected EGUs, of the 

“system of emission reduction” that is the “best,” taking into 

account “cost” and other factors, and that is “adequately 

demonstrated.” Those components include certain interpretations 

and applications. For example, because the affected EGUs must be 

 

497 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. 

498 UARG comment at 2-3. 
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able to achieve their emission standards through application of 

the BSER, the BSER must be something that the EGUs themselves 

can implement. Likewise, because the emission standards must 

apply to the affected source category, actions taken by affected 

sources that do not result in emission reductions from the 

source category –- that is, offsets (e.g., the planting of 

forests to sequester CO2) –- do not qualify for inclusion in the 

BSER. Under this rule, 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. 
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Moreover, the application of building blocks 2 and 3 to 

affected EGUs has a number of unique characteristics that 

negate, or at least 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 the cleaner (that is, less CO2-

intensive) processes of shifting dispatch from steam generators 

to existing NGCC units, and from both steam generators and NGCC 

units to renewable generators. 

The physical properties of electricity and the highly 

integrated nature of the electricity system allow the use of 

these cleaner processes to generate the same amount of 

electricity. In addition, the electricity sector is primarily 

domestic -- little electricity is exported outside the U.S. -- 

and there is low capacity for storage. In addition, the 

electricity sector is highly regulated, planned, and 

coordinated. As a result, holding demand constant, an increase 

in one type of generation will result in a decrease in another 

type of generation. Moreover, the higher-emitting generators, 

which are fossil fuel-fired, have higher variable costs than 
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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 a wide variety 

of reasons, many of which are directly related to the system’s 

primary purposes and functions, as well as for environmental 

reasons. As a result, at present, there is a well-established 

network of business and operational relationships and past 

practices that supports building blocks 2 and 3. As noted 

elsewhere, a large segment of steam generators already have 

business relationships with existing NGCC units, and a large 

segment of all fossil fuel-fired EGUs already own, co-own, or 

have invested in 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 
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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 

emission reduction ... adequately demonstrated.” Moreover, the 

examples offered by commenters appear to be premised on 

government action mandating actions not implementable by 

emitting sources (e.g., that a government would “require[e] car 

owners to shift some of their travel to buses, or ... require[e] 

there to be more electric vehicle purchases”), whereas the 

measures in building blocks 2 and 3 can be implemented by the 

affected EGUs. 

4. Relationship between a source’s implementation of building 

blocks 2 and 3 and its emissions. 
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In this section, we discuss the relationship between an 

affected EGU’s implementation of the measures in building blocks 

2 and 3 and that affected EGU’s own generation and emissions. As 

discussed above, an affected EGU subject to a CAA section 111(d) 

state plan that imposes an emission rate-based standard may 

achieve that standard in part by implementing the measures in 

building block 2 (for a steam generator) and building block 3 

(for a steam generator or combustion turbine). That is, an 

affected EGU may invest in low- or zero-emitting generation and 

may apply credits from that generation against its emission 

rate. Those credits reduce the affected EGU’s emission rate and 

thereby help it to achieve its emission limit. 

In addition, the additional low- or zero-emitting 

generation that results from the affected EGU’s investment will 

generally displace higher-emitting generation. This is because, 

as described above, higher-emitting generation generally has 

higher variable costs, reflecting its fuel costs, than, at 

least, zero-emitting generation. Displacement of higher-emitting 

generation will lower overall CO2 emissions from the source 

category of affected EGUs. 

If an affected EGU implements building block 2 or 3 by 

reducing its own generation, it will reduce its own emissions. 
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However, the affected EGU may also or alternatively choose to 

implement building block 2 or 3 by investing in lower- or zeroemitting generation that does not, in and of itself, reduce the 

amount of its own generation or emissions. Even so, 

implementation of building blocks 2 and 3 will reduce CO2 from 

some affected EGUs, and therefore reduce CO2 on a source 

category-wide basis. 

This outcome is, however, consistent with the requirements 

of CAA section 111(d)(1) and (a)(1). To reiterate, CAA section 

111(d)(1) requires that “any existing source” have a “standard 

of performance,” defined under CAA section 111(a)(1) as “a 

standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the application 

of the best system of emission reduction ... adequately 

demonstrated [BSER] ....” These provisions require by their 

terms that “any existing source” must have a “standard of 

performance,” but nothing in these provisions requires a 

particular amount –- or, for that matter, any amount -- of 

emission reductions from each and every existing source. That 

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 
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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. 

The application of the building blocks has an impact that 

is similar to that of an emissions trading program, under which, 

overall, the affected sources reduce emissions, but any 

particular source does not need to reduce its emissions and, in 

fact, may increase its emissions, as long as it purchases 

sufficient credits or allowances from other sources. In fact, we 
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expect that that many states will carry out their obligations 

under this rule by imposing standards of performance that 

incorporate trading or other multi-entity generation-replacement 

strategies. Indeed, any emission rate-based standard may not 

necessarily result in emission reductions from any particular 

affected source (or even all of the affected sources in the 

category) as a result of the ability of the particular source 

(or even all of them) to increase its production and, therefore, 

its emissions, even while maintaining the required emission 

rate. 

5. Reduced generation and 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 from either the source-category perspective or the 

individual-source 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 
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reduced generation, and with all building blocks incorporating 

the option of investing through the purchase of rate-based 

emission credits or mass-based emission allowances. Reduced 

generation is linked to 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 existing NGCC units would 

determine a portion of the 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 lower- or 

zero-emitting generating capacity that could be provided, would 

determine a portion of the amount of the generation reduction 

component of the BSER for affected fossil fuel-fired steam EGUs 

as well as the entire generation reduction component of the BSER 

for affected NGCC units. This section discusses the reasons that 

reduced generation is one of the set of reasonable and wellestablished actions that affected EGUs can implement to achieve 

their emission limits. It should be noted that strictly 

speaking, because we are not identifying reduced generation as 

the BSER, it is not necessary to explain that reduced generation 

meets the criteria for the BSER, but having said that, we note 

that in fact, reduced generation does meet the criteria for the 

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BSER and, to highlight its reasonableness as a means for EGUs to 

achieve their emission limits, we explain why. 

a. Background. As noted, for both rate-based and mass-based 

state plans, affected EGUs may take a set of actions to comply 

with their emission standards. An affected EGU may comply with 

an emission rate-based standard (e.g., a limit on the amount of 

CO2 per MWh) by acquiring, through one means or another, credits 

from lower- or zero-emitting generation (building blocks 2 or 3) 

to reduce its emission rate for compliance purposes. In 

addition, the affected EGU may reduce its generation, and if it 

does so, it then needs to acquire fewer of those credits to meet 

its emission rate.499 Under these circumstances, the affected EGU 

would in effect replace part of its higher-emitting generation 

with lower- or zero-emitting generation. On the other hand, an 

affected EGU that is subject to a mass-based standard -- for 

example, a requirement to hold enough allowances to cover its 

emissions (e.g., one allowance for each ton of emissions in any 

year) -- may comply at least in part by reducing its generation 

 

499 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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and, thus, its emissions. Therefore, one type of action that an 

affected EGU may take to achieve either of these emission limits 

is to reduce its generation. Further, reduced generation offers 

a pathway to compliance in-and-of-itself. That is, a state may 

adopt a mass-based goal, assign mass-based standards to its 

sources, and those sources may comply with their mass-based 

limits by, in addition to implementing building block 1 

measures, reducing their generation in the appropriate amounts, 

and without taking any other actions. 

b.Well-established use of reduced generation to comply with 

environmental requirements. Reduced generation is a wellestablished method for fossil fuel-fired power plants to comply 

with their emission limits. 

 Reduced generation in the amounts contemplated in this rule 

reduces emissions from the affected sources, but because of the 

integrated and interconnected nature of the power sector, can be 

accommodated without significant cost or disruption. The 

electric transmission grid interconnects the nation’s generation 

resources over large regions. Electric system operators 

coordinate, control, and monitor the electric transmission grid 

to ensure cost-effective and reliable delivery of power. These 

system operators continuously balance electricity supply and 

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demand, ensuring that needed generation and/or demand resources 

are available to meet electricity demand. Diverse resources 

generate electricity that is transmitted and distributed through 

a complex system of interconnected components to end-use 

consumers. 

The electricity system was designed to meet these core 

functions. The three components of the electricity supply system 

-- generation, transmission and distribution -- coordinate to 

deliver electricity from the point of generation to the point of 

consumption. This interconnectedness is a fundamental aspect of 

the nation’s electricity system, requiring a complicated 

integration of all components of the system to balance supply 

and demand and a federal, state and local regulatory network to 

oversee the physically interconnected network. Electricity from 

a diverse set of generation resources such as natural gas, 

nuclear, coal and renewables is distributed over high-voltage 

transmission lines. The system is planned and operated to ensure 

that there are adequate resources to meet electricity demand 

plus additional available capacity over and above the capacity 

needed to meet normal peak demand levels. System operators have 

a number of resources potentially available to meet electricity 

demand, including electricity generated by electric generation 
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units of various types as well as demand-side resources. 

Importantly, if generation is reduced from one generator, 

safeguards are in place to ensure that adequate supply is still 

available to meet demand. We describe these safeguards in the 

background section of this preamble. 

Both Congress and the EPA have recognized reduced 

generation as one of the measures that fossil fuel-fired EGUs 

may implement to reduce their emissions of air pollutants and 

thereby achieve emission limits. Congress, in enacting the 

allowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO2 emitted, 

explicitly recognized that fossil fuel-fired EGUs could meet 

this requirement by reducing their generation. In fact, Congress 

anticipated that fossil fuel-fired EGUs may choose to comply 

with the SO2 emission limits by reducing utilization, and 

included provisions that specifically addressed reduced 

utilization. For example, CAA section 408(c)(1)(B) includes 

requirements for an owner or operator of an EGU that meets the 

Phase 1 SO2 reduction obligations and the NOx reduction 

obligations “by reducing utilization of the unit as compared 

with its baseline or by shutting down the unit.” 
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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. 

Examples include rulemakings to impose requirements that sources 

implement BART to reduce their emissions of air pollutants that 

cause or contribute to visibility impairment. As explained 

earlier, for certain older stationary sources that cause or 

contribute to visibility impairment, including fossil fuel-fired 

EGUs, states must determine BART on the basis of five statutory 

factors, such as costs and energy and non-air quality impacts.500

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.”501 Both the statutory factors and the 

regulatory definition resemble the definition of the BSER under 

CAA section 111(a)(1) (although, as noted, the statutory 

definition of BART is more technology focused than the 

definition of BSER). In its regional haze SIP, the State of New 

 

500 CAA section 169A(g)(2). 501 40 C.F.R. § 51.301. 
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York determined that BART for the NOX emissions from two coalfired boilers that served as peaking units was caps on baseline 

emissions rates and annual capacity factors of 5 percent and 10 

percent, respectively.502 

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 

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 

 

502 77 Fed. Reg. 24,794, 24,810 (Apr. 25, 2012). 
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emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements.503

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.504

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 

 

503 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). 

504 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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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,”505 or “legally and 

practicably enforceable by a state or local air pollution 

control agency.”506 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.”507 These 

regulatory provisions make clear that restrictions on potential 

to emit include both “air pollution control equipment” and 

“restrictions on hours of operation,” and indicate that these 

are equally cognizable means of restricting emissions to comply 

with, or avoid, CAA requirements.508 

 

505 40 CFR 52.21(b)(4)(emphasis added). 506 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. 

507 See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 

programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 

programs), 70.2 (addressing title V operating permit programs), 

and 63.2 (addressing hazardous air pollutants). 

508 See, e.g., 52.21(b)(4). 
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As one of many examples of a fossil-fuel fired EGU taking 

restrictions on hours of operation for the purpose of avoiding 

CAA obligations, Manitowoc Public Utilities in Wisconsin 

obtained a title V renewal permit that limited the operating 

hours of the single simple-cycle combustion turbine to not more 

than 194 hours per month, averaged over any consecutive 12 month 

period, as part of limiting its potential to emit for volatile 

organic compounds below the title V threshold of 100 tpy, and 

carbon monoxide, nitrogen oxides and sulfur dioxide below the 

PSD threshold of 250 tpy.509 As another example, Sunbury 

Generation LP in Pennsylvania obtained a minor new source 

 

509 See Final Operation Permit No. 436123380-P10 for Manitowoc 

Public Utilities - Custer Street (Wis. Dept. Nat. Res., 

8/19/2013), Condition ZZZ.1.a(1) at p. 9 (Limiting potential to 

emit) and n. 11 (“These conditions are established so that the 

potential emissions for volatile organic compounds will not 

exceed 99 tons per year and potential emissions for carbon 

monoxide, nitrogen oxides and sulfur dioxide emissions from the 

facility will not exceed 249 tons per year.”). See also Analysis 

and Preliminary Determination for the Renewal of Operation 

Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/21/2013) at p. 5 

(noting that the “existing facility is a major source under Part 

70 because potential emissions of sulfur dioxide, nitrogen 

oxides and carbon monoxide exceed 100 tons per year. The 

existing facility is a minor source under PSD and an area source 

of federal HAP” and further noting that after renewal, “the 

facility will continue to be a major source under Part 70 

because potential emissions of sulfur dioxide, nitrogen oxides 

and carbon monoxide exceed 100 tons per year. The facility will 

also continue to be a minor source under PSD and an area source 

of federal HAP.”). 
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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.510 The Legal Memorandum includes numerous other 

examples of power plants accepting permit limits that reduce 

generation to meet, or avoid the need to meet, emission limits. 

There are several ways that an affected EGU may implement 

reduced 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 

 

510 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.511 

c. Other aspects of reduced generation. 

At the levels reflected in the final building blocks, 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 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. 

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 

 

511 Although, as noted, it is not necessary to demonstrate that 

reduced generation meets the requirements for the BSER, we note 

that the just-described examples make clear that reduced 

generation would constitute a “system of emission reduction” 

(because it is an action power plant owners or operators can 

take to reduce their emissions) that is “adequately 

demonstrated” (because Congress and the EPA have recognized it 

and on numerous occasions, power plants have relied on it). 
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the emission limits of this rule, because of the availability of 

the measures in building blocks 2 and 3, and because the grid is 

interconnected and the electricity system is highly planned, 

reductions in generation by fossil fuel-fired EGUs in the amount 

contemplated under this rule, and occurring over the lengthy 

time frames provided under this rule, will result in replacement 

generation that generally is lower- or zero-emitting. Mechanisms 

are in place in both regulated and deregulated electricity 

markets to assure that substitute generation will become 

available and/or steps to reduce demand will be taken to 

compensate for reduced generation by affected EGUs. As a result, 

reduced generation will not give rise to reliability concerns or 

have other adverse effects on the utility power sector and are 

of reasonable cost for the affected source category and the 

nationwide electricity system. All these results come about 

because the operation of the electrical grid through integrated 

generation, transmission, and distribution networks creates 

substitutability for electricity and electricity services, which 

allows decreases in generation at affected fossil fuel-fired 

steam EGUs to be replaced by increases in generation at affected 

NGCC units (building block 2) and allows decreases in generation 

at all affected EGUs to be replaced by increased generation at 
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new lower- and zero-emitting EGUs (building block 3). Further, 

this substitutability 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.512 

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.”513 We disagree with this concern, for the following 

reasons. 

As discussed, in this final rule, we are identifying the 

BSER as the combination of the three building blocks. Building 

blocks 2 and 3 entail substitution of lower- or zero-emitting 

generation for higher-emitting generation, and one component of 

that substitution is reduced generation. Accordingly, our 

identification of the BSER in this final rule does not “rel[y] 

primarily” on reduced utilization as the BSER. Rather, the BSER 

 

512 Although, as noted, it is not necessary to demonstrate that 

reduced generation meets the requirements for the BSER, this 

discussion make clear that reduced generation meets the BSER 

criteria of reducing emissions, being of reasonable cost, not 

having adverse implications for energy or non-air quality 

pollutants, and not resulting in adverse impacts on the utility 

power sector. 

513 EEI comment, at 284. 

Formatted: Highlight
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is, in addition to building block 1, the substitution of loweror zero-emitting generation for higher emitting generation, and 

reduced utilization may be a way to implement that substitution 

and is one of numerous methods that affected EGUs may employ to 

achieve or help achieve the emission limits established by these 

emission guidelines. The commenter’s concerns over a perceived 

lack of a limiting principle cannot be taken to mean that 

reduced generation cannot be considered to be a method for 

affected EGUs to achieve their emission limits. 

Moreover, reduced generation, as applied to affected EGUs 

in this rule, is limited in a number of respects. The amount of 

reduced generation is the amount of replacement generation that 

is lower- or zero- emitting, that is of reasonable cost, that 

can be generated without jeopardizing reliability, and that 

meets the other requirements for the BSER. As discussed, that 

amount is the amount of generation in building blocks 2 and 3.514

Finally, as discussed, the integrated nature of the 

electricity system, coupled with the high substitutability of 

 

514 The EPA notes that affected EGUs are not actually required to 

collectively reduce generation by the amount represented in the 

BSER, and may collectively reduce generation by more or less 

than that amount. Individual affected EGUs are free to choose 

reduced generation or other means of reducing emissions, as 

permitted by their state plans, in order to achieve the 

standards of performance established for them by their states. 
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electricity, allows EGUs to reduce their generation without 

adversely affecting the availability of their product. Those 

characteristics facilitate replacement of generation that has 

been reduced, and for that reason, EGUs have a long history of 

reducing their generation and either replacing it directly or 

having it replaced through the operation of the interconnected 

electricity system through measures similar to those in building 

blocks 2 and 3. Thus, an EGU can either directly replace its 

generation, or simply reduce its generation, and in the latter 

case, the integrated grid, combined with the high degree of 

planning and various reliability safeguards, will result in 

entities providing replacement generation. This means that 

consumers receive exactly the same amount of the same product, 

electricity, after the reduced generation that they received 

before it. No other industry is both physically interconnected 

in this manner and manufactures such a highly substitutable 

product; as a result, the use of reduced generation is not 

easily transferrable to another industry. 
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6. Reasons that this rule is within the EPA’s statutory 

authority and does not represent over-reaching. 

In this section, we respond to adverse comments that the 

EPA is overreaching in this rulemaking by attempting to direct 

the energy sector. These commenters construed the proposed 

rulemaking as the EPA proposing to mandate the implementation of 

the measures in the building blocks, including investment in 

renewable energy and 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 
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(UARG)515 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.”516 Commenters assert that in this rule, 

the EPA is taking the actions that the UARG opinion cautioned 

against. For the reasons discussed below, these comments are 

incorrect and misunderstand fundamental aspects of this rule. In 

addition, to the extent these comments address either building 

block 4 or the portfolio approach they are moot, because the EPA 

is not finalizing those elements of the proposal. 

In this rule, the EPA is following the same approach that 

it uses in any rulemaking under CAA section 111(d), which is 

designed to regulate the air pollutants from the source category 

at issue. First, the EPA identifies the BSER to reduce harmful 

air pollution. Second, based on the BSER, the EPA promulgates 

emission guidelines, which generally take the form of emission 

 

515 134 S. Ct. 2427 (2014). 516 Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014) (citations omitted). 
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rates applicable to the affected sources. In this case, the EPA 

is promulgating a uniform CO2 emission performance rate for 

steam-generating EGUs and a uniform CO2 emission performance rate 

for combustion turbines, and the EPA is translating those rates 

into a combined emission rate and equivalent mass limit for each 

state. These emission guidelines serve as the guideposts for 

state plan requirements. The states, in turn, promulgate 

emission standards or standards of performance 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 

of compliance options to achieve their emission limits. Those 

options include various means of implementing the building 
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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 natural gas co-firing.517 

As some indication of the diverse set of actions we expect 

to comply with the requirements of this rule, we note that 

distributed generation from renewables and demand-side energy 

efficiency programs, in particular, are expected to be a 

significant compliance method, in light of their low costs. In 

addition, the National Association of Clean Air Agencies (NACAA) has 

issued a report that provides a detailed discussion of 25 approaches 

to CO2 reduction in the electricity sector.518 In addition, we note 

 

517 In fact, the EPA is expressly precluded from mandating 

specific controls except in certain limited circumstances. See 

42 U.S.C. § 7411(b)(5). For instance, the EPA is authorized to 

mandate a particular “design, equipment, work practice, or 

operational standard, or combination thereof,” when it is “not 

feasible to prescribe or enforce a standard of performance” for 

new sources. 42 U.S.C. § 7411(h)(1). CAA section 111(h) also 

highlights for us that while “design, equipment, work practice, 

or operational standards” may be directly mandated by the EPA, 

CAA section 111(a)(1) encompasses a broader suite of measures 

for consideration as the BSER. 

518 NACAA, “Implementing EPA’s Clean Power Plan: A Menu of 

Options (May 2015) 

http://www.4cleanair.org/NACAA_Menu_of_Options. NACAA describes 

itself as “the national, non-partisan, non-profit association of 

air pollution control agencies in 41 states, the District of 

Columbia, four territories and 116 metropolitan areas.” Id.

Formatted: English (United States)
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that the nine RGGI states -- Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island 

and Vermont – have indicated that they intend to maintain their 

current state programs, which this rule would allow, and there 

are reports that other states may seek to join RGGI.519

Similarly, California has indicated that it intends to maintain 

its current state program, which this rule would allow. Other 

states could employ the types of methods used in Oregon, 

Washington, Colorado, or Minnesota, described in the background 

section of this preamble. 

In this rule, as with all CAA section 111(d) rules, the EPA 

is not directly regulating any entities. Moreover, the EPA is 

not finalizing the proposed portfolio approach. Accordingly, the 

EPA neither requiring nor authorizing the states to regulate 

non-affected EGUs in their CAA 111(d) plans .520

It is certainly reasonable to expect that compliance with 

these air pollution controls will have costs, and those costs 

will affect the electricity sector by discouraging generation of 

 

519 Martinson, Erica, “Cap and trade lives on through the 

states,” Politico (May 27, 2014) 

http://www.politico.com/story/2014/05/cap-and-trade-states107135.html 

520 A state may regulate non-EGUs as part of a state measures 

approach, but those measures would not be federally enforceable. 

Formatted: English (United States)
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fossil fuel-fired electricity and encouraging alternative means 

of generating electricity. But for affected EGUs, air pollution 

controls necessarily entail costs that affect the electricity 

sector and, in fact, the entire nation, regardless of what BSER 

the EPA identifies as the basis for the controls. For example, 

had some type of add-on control such as CCS been available as 

the BSER for coal-fired EGUs, sources that complied by 

installing that control would incur higher costs. As a result, 

generation from coal-fired EGUs would be expected to decrease 

and be replaced at least in part by generation from existing 

NGCC units and new renewables because those forms of generation 

would see their competitive positions improved. 

This basic fact that the EPA regulations of air pollutants 

from affected EGUs invariably affect the utility sector is wellrecognized and in no way indicates that such regulations exceed 

the EPA’s authority. In revising CAA section 111 in the 1977 CAA 

Amendments, Congress explicitly acknowledged that the EPA’s 

rules under CAA section 111 for EGUs would significantly impact 

the energy sector.521 The Courts have recognized that, too. The 

 

521 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: 
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U.S. Supreme Court, in its 2011 decision that the CAA and the 

EPA actions it authorizes displace any federal common law right 

to seek abatement of CO2 emissions from fossil-fuel fired power 

plants, emphasized that CAA section 111 authorizes the EPA – 

which the Court identified as the “expert agency” – to regulate 

CO2 emissions from these sources in a manner that balances “our 

Nation’s energy needs and the possibility of economic 

disruption:” 

The appropriate amount of regulation in any particular 

greenhouse gas-producing sector cannot be prescribed 

in a vacuum: as with other questions of national or 

 

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 

Leg. Hist. at 324 (referring to H.R. Rep. No. 95-294, 

95th Cong., 1st Sess. 188 (1977), at 183-95, 4 Leg. 

Hist. at 2651-62, Remarks of Senator Muskie 

introducing S. 252 for debate, 123 Cong. Rec. 18018 

(1977), 3 Leg. Hist. at 717.) Indeed, the Reports from 

both Houses on the Senate and House bills illustrate 

very clearly that Congress itself was using a longterm 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 Leg. Hist. 1371; H.R. Rep. No. 95-294, 95th 

Cong., 1st Sess. 188 (1977), 4 Leg. Hist. 2465.] 
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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.522

Similarly, the D.C. Circuit, in its 1981 decision upholding the 

EPA’s rules to reduce SO2 emissions from new coal-fired EGUs 

 

522 American Electric Power v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011). 
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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.523

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.”524 This rule has “economic, environmental, and 

 

523 Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981). 524 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). The 

Court supported this statement with a lengthy quotation from a 

scholarly article, which stated, in part: 

Consider for a moment the chain of collective 

decisions and their effects just in the case of 

electric utilities. Petroleum imports can be conserved 

by switching from oil-fired to coal-fired generation. 

But barring other measures, burning high-sulfur 

Eastern coal substantially increases pollution. Sulfur 

can be “scrubbed” from coal smoke in the stack, but at 

a heavy cost, with devices that turn out huge volumes 

of sulfur wastes that must be disposed of and about 

whose reliability there is some question. Intermittent 

control techniques (installing high smokestacks and 
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energy” impacts, as Congress and the Courts expect in a CAA 

section 111 rule, but those impacts do not mean that the EPA is 

precluded from promulgating the rule. 

 As noted above, in this rule, to control CO2 emissions from 

affected EGUs, the EPA first considered more traditional air 

pollution control measures, including supply-side efficiency 

improvements, fuel-switching (for CO2 emissions, that entails cofiring with natural gas), and add-on controls (for CO2 emissions, 

that entails CCS). However, it became apparent that even if the 

 

switching off burners when meteorological conditions 

are adverse) can, at lower cost, reduce local 

concentrations of sulfur oxides in the air, but cannot 

cope with the growing problem of sulfates and 

widespread acid rainfall. Use of low-sulfur Western 

coal would avoid many of these problems, but this coal 

is obtained by strip mining. Strip-mining reclamation 

is possible, but substantially hindered in large areas 

of the West by lack of rainfall. Moreover, in some 

coal-rich areas the coal beds form the underground 

aquifer and their removal could wreck adjacent farming 

or ranching economies. Large coal-burning plants might 

be located in remote areas far from highly populated 

urban centers in order to minimize the human effects 

of pollution. But such areas are among the few left 

that are unspoiled by pollution and both 

environmentalists and the residents (relatively few in 

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 BSER525 and 

established the same uniform CO2 emission performance rates, the 

affected EGUs would rely on less expensive ways to achieve their 

emission limits. Specifically, instead of relying on co-firing 

and CCS, the affected EGUs generally would replace their 

generation with lower- or zero-emitting generation– the measures 

in building blocks 2 and 3 -- because those measures are 

significantly less expensive and already well-established as 

pollution control measures. Indeed, some affected EGUs have 

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.526

We expect that many sources will choose to comply with 

their emission limits through the measures in building blocks 2 

 

525 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. 

526 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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and 3, but contrary to the assertions of some commenters, this 

will not result in unprecedented and fundamental alterations to 

the energy sector. As discussed above, Congress relied on the 

same measures as those the EPA is including in building blocks 2 

and 3 as essential parts of the basis for the Title IV emission 

limits for fossil fuel-fired EGUs, and the EPA did the same for 

the emission limits in various rules for those same sources. In 

addition, 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 that such sources be 
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subject to the PSD requirements.527 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, 

as noted above, this final rule does not require or authorize 

the states to include entities other than affected EGUs in their 

CAA section 111(d) state plans, and as a result, those entities 

will not come under CAA jurisdiction528 and the parts of the 

economy that they represent will not be regulated by the EPA. 

7. Relative stringency of requirements for existing sources and 

new and modified sources. 

 

527 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2443 

(2014). 

528 States may regulate non-affected EGUs through a state 

measures approach, but those regulations would not be federally 

enforceable. 
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Commenters also objected that the proposed CAA section 

111(d) standards are more stringent than the standards for new, 

modified or reconstructed sources, and they assert that setting 

section 111(d) standards that are more stringent than 111(b) 

standards would be illogical, contrary to precedent, contrary to 

the intent of the remaining useful life exception, and arbitrary 

and capricious.529 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 

 

529 ACC et al. (Associations) comments at 40, Luminant comments 

at 89. 
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contrast, the compliance time for the CAA section 111(d) rule 

does not begin until seven 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 eight 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.In addition, the timetables for compliance with the 

111(b) and 111(d) rules should be compared not only with each 

other but also with the 8-year review schedule required for 

section 111(b) rules under CAA section 111(b)(1)(B). It is 

evident that the 111(b) requirements apply to new sources that 

construct beginning in 2015, whereas existing sources are 

uncontrolled until 2022. In addition, the EPA would be required 

to review and, if necessary, revise the CAA section 111(b) rule 

in 2023, shortly after the interim compliance time for the CAA 

section 111(d) rule begins. As a result, application of 111(d) 

regulatory requirements will only just be beginning when the 

111(b) standards will already be on the cusp of a mandatory 

review that will reassess the BSER factors to determine the 
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appropriate stringency for new source emission standards into 

the future, and with any revision, the “new” sources under the 

current (b) rule will become existing sources. This heightens 

the significance of the different compliance period. 

 Even after the section 111(d) rule takes effect in 2022, 

the flexibility that this rule offers the states has important 

implications for its stringency. Because the requirements of 

this rule are phased in over the 2022-2030 period, the initial 

compliance obligations are significantly less stringent than the 

final compliance obligations. For example, because of the 

flexibility of the section 111(d) requirements, states are not 

required to impose emission reduction requirements on their 

sources during the first years of the 2022-2030 compliance 

period. In addition, because the requirements are phased in, 

states may choose to apply a gradual phase-in of the reductions. 

We estimate that if states choose to impose the requirements in 

a proportional amount each year, the requirements for steam 

generators by 2022 would result in an average emissions 

performance rate of 1,764 lb. CO2/MWh and by 2023, an average 

emission rate of 1,698 lb. CO2/MWh. In fact, with that estimate, 

it is not until 2029 that the average rate drops below 1,400 (to 

1,359), and it does not reach 1,305 until 2030. These rates at 

Deleted: .
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these points in time provide important points of comparison with 

the standard of performance required for new steam EGUs under 

the section 111(b) rule, which, as noted, is 1400 lb. CO2/MWh. By 

no later than 2023, the EPA will be required under CAA section 

111(b)(1)(B) to “review and, if appropriate, revise” that 1400 

standard. Thus, at the latest time (2023) that the 1,400 

standard will apply to new steam EGUs before the EPA will be 

required to review it for possible revision, the section 111(b) 

standard will be more stringent than the existing source 

requirements, which, to reiterate, may not impose any emission 

reduction requirements on existing steam EGUs and which, if the 

states implement it proportionally, would result in emission 

limits of 1,698. 

The emission rate for existing NGCC units over the 2022-

2030 period shows the same characteristics. States need not 

impose any emission reduction requirements on their existing 

NGCC units during the first years. If states choose to implement 

those requirements proportionally, in 2022, the average rate 

would be 910 lb. CO2/MWh, and in 2023 it would be 899.530 As a 

result, at the latest time (2023) that the 1,000 lb. CO2/MWh 

standard will apply to new NGCC units before the EPA will be 

 

530 This rate does not fall to 771 lb. CO2/MWh until 2030.
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required to review it for possible revision, the standard would 

not be less stringent than the existing source requirements, 

which do not necessarily entail any emission reduction 

requirements in a particular year from existing sources (so long 

as the interim goal is met), and, if the states choose to 

implement the requirements proportionally, would be less 

stringent than the average emission rate limit (899), but not 

substantially so. To reiterate, the fact that the new source 

standard applies immediately while the existing source standard 

does not apply for 7 years is an important reason why the new 

source standard cannot be considered less stringent in fact. 

 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 from the EPA’s 

guidelines, and may be expected to authorize trading of massbased emission allowances or rate-based emission credits. 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. The EPA has frequently required that sources meet a 

more stringent limit when they are allowed compliance 
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flexibility, particularly, the opportunity to trade.531 This 

distinction is another reason why the CAA section 111(d) rule 

cannot be said to in fact be more stringent than the CAA section 

111(b) rule. 

 Moreover, even if commenters were correct that the section 

111(d) requirements for existing sources are more stringent than 

the section 111(b) requirements for new sources, that would not, 

by itself, call into question the reasonableness of either 

standard. The stringency of the requirements for each source 

subcategory is, of course, a direct function of the BSER 

identified for that source subcategory. In this rulemaking, we 

explain the basis for the BSER for existing sources, and why we 

do not include certain measures, such as CCS; and in the section 

111(b) rulemaking, we explain the basis for the BSER for new 

sources, and why we do not include certain measures, such as the 

building blocks. As long as the BSER determination is reasonable 

and the resulting emission limits meet other applicable 

requirements, those emission limits are valid, even if the one 

 

531 See, e.g., EPA, “Improving Air Quality with Economic 

Incentive Programs,” EPA-452/R-01-001, at 82 (2001) (requiring 

that economic incentive programs show an environmental benefit, 

such as “reducing emission reductions generated by program 

participants by at least 10 percent”). 

http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf. 

Commented [A14]: Further, the 111(b) standards serve a 

separate purpose—ensuring that when significant resources are 

invested in building, reconstructing, or modifying a new source, the 

new or modified infrastructure meets a minimum standard of 

performance in terms of its emissions of harmful pollutants. The 

111(d) standards, in contrast, are addressing the entire group of 

existing sources of a pollutant, and the pollution generated by those 

sources. The approach with existing sources is necessarily different, 

as the standards apply outside of a specific event (construction, 

modification, or reconstruction)—the design of the Clean Power 

Plan is responsive to the greater need to provide flexibility to 

existing sources and to effectively address carbon pollution from 

existing EGUs—-the largest source of carbon pollution in the 

country. 
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for new sources is less stringent than the one for existing 

sources. No provision in section 111, nor any statement in its 

legislative history, nor any of its caselaw, indicates that the 

standards for new sources must be more stringent than the 

standards for existing sources. 

C. Building Block 1—Efficiency Improvements at Affected CoalFired Steam EGUs 

The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 

reduce the carbon intensity of generation at individual coalfired 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 

EGUs by reducing their fuel costs. 

An EGU’s heat rate is the amount of fuel energy input 

needed (Btu, higher heating value basis) to produce 1 kWh of net 
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electrical energy output.532 In 2012, the generation-weighted 

average annual heat rate of the 884 coal-fired EGUs included in 

EPA’s building block 1 analysis was approximately 9,732 Btu per 

gross kWh.533 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 carbonintensity of generation. 

We conducted several analyses to assess the potential for 

heat rate improvements from the coal-fired EGU fleet. As in the 

proposal, we employed a unit-specific approach that compared 

each EGU’s performance against its own historical performance in 

lieu of directly comparing an EGU’s performance against other 

EGUs with similar characteristics. Accordingly, as described 

below, our method effectively controls for the characteristics 

and factors of an EGU that typically remain constant over time 

(e.g., a unit is unlikely to dramatically increase or decrease 

 

532 Typically, the units of measure used for heat rate (e.g., 

Btu/kWh-net) indicate whether a given value is based on the 

gross output or net output. Net heat rate is always higher than 

gross heat rate; in coal-steam units, net heat rate can be 5–10% 

higher than gross heat rate. 

533 Similarly, within each interconnection, the generationweighted average annual heat rates for those coal-fired EGUs in 

our study population were 9,700 Btu per gross kWh (Eastern); 

9,888 Btu per gross kWh (Western); and 9,789 Btu per gross kWh 

(Texas). 
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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 

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 
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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 duct leakage 

controls. 
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As noted below in sections V.C.1.b and V.C.3, the EPA 

acknowledges that some equipment upgrades implemented by EGUs 

during the 11-year study period are reflected in the hourly heat 

rate data. Therefore, we made two refinements to our analyses of 

heat rate improvement potential. First, we refined our 

statistical approaches to use each EGU’s gross heat rate from 

2012 -- the final year of the 11-year study period -- as the 

baseline for calculating heat rate improvement potential. By 

comparing each EGU’s best historical gross heat rate with its 

2012 gross heat rate, our analyses account for the enduring 

effects on heat rate of any equipment upgrades or best practices 

that an EGU implemented during the study period. Heat rate 

improvement measures that an EGU maintains in 2012 are reflected 

in that baseline, and thus are not treated as evidence that the 

EGU can further improve heat rate. Additionally, in part because 

of limitations on the information available to us regarding 

which equipment upgrades have been or could be implemented at 

individual EGUs, as well concerns about double-counting, we have 

conservatively decided not to add a separate equipment upgrade 

component to our estimate of heat rate improvement potential. 

Nonetheless, we remain confident that additional equipment 

upgrades (including measures that are unambiguously equipment 
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upgrades, such as turbine overhauls) are possible at many coalfired EGUs, as supported by numerous commenters, the Sargent & 

Lundy study534 (S&L) and other industry reports and studies. Many 

of these reports and studies are referenced in the TSD developed 

for the proposed rule, as well as in the GHG Mitigation Measures 

TSD supporting the final CPP. 

Several commenters criticized the fact that the proposal 

assessed potential heat rate improvement on a nationwide basis. 

These commenters suggested instead that we narrow the geographic 

scope of our analysis, generally identifying a state-by-state 

approach as a preferred alternative. In light of commenters’ 

concerns about using a single nationwide approach, as well as 

for reasons described in Section V.A and elsewhere in this 

preamble, the final rule assesses potential heat rate 

improvement regionally, within the Eastern, Western and Texas 

Interconnections.535

 

534 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. 

535 The geographic area within the Texas Interconnection 

generally corresponds to the portion of the state of Texas 

covered by ERCOT (the Electric Reliability Council of Texas). 

Additional portions of the state of Texas are located within the 

Eastern and Western Interconnections. 
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For the final rule, we performed several analyses to 

determine what heat rate improvement was achievable in each 

interconnection from best practices and equipment upgrades. As 

in the proposal, these analyses used the 11-year dataset of EGU 

hourly gross heat rate data from 2002 to 2012. As discussed 

further in the GHG Mitigation Measures TSD, our reliance on 

these gross heat rate data was reasonable given that (1) these 

data are the only comprehensive data available to the EPA, and 

(2) heat rate is proportional to CO2 emission rate. 

As in the proposal, we used more than one analytical method 

to evaluate the opportunity for EGUs to reduce their CO2

emissions through heat rate improvements. Our final methodology 

uses three different analytical approaches based on refinements 

of the two approaches described at the proposal stage. We call 

these final approaches: (1) the “efficiency and consistency 

improvements under similar conditions” approach; (2) the “best 

historical average performance” approach; and (3) the “best 

historical average performance under similar conditions” 

approach. As described below and in the GHG Mitigation Measures 

TSD, each approach provides an independently reasonable way to 

estimate the potential for heat rate improvements by EGUs in 

each region. However, rather than select a potential heat rate 
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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 percent536). Thus, for example, one bin would contain 

all of an EGU’s hourly gross heat rate data generated during the 

11-year study period while that EGU was operating at 80- to 89-

percent capacity while ambient temperatures were between 70oF and 

79oF. 

 

536 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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As we explained at proposal and as discussed further in the 

GHG Mitigation Measures TSD, ambient temperature and hourly 

capacity factor are important conditions that influence heat 

rate at individual EGUs. By separating the EGU-specific data 

into bins based on these variables, and only directly comparing 

data within a bin, we were largely able to control for the 

influence of those variables on an EGU’s heat rate. Accordingly, 

having controlled for these two external factors, and having 

already controlled for unit-specific factors affecting heat rate 

by analyzing the data for each EGU in isolation, we are 

confident that the remaining variation in each bin’s data was 

primarily driven by factors under the EGU operator’s control. 

After allocating an individual EGU’s data across the bins, 

we next established a benchmark for each bin based on the best 

hourly gross heat rate accounting for outliers (i.e., we set the 

benchmark at the 10th percentile hourly gross heat rate value) 

during any consecutive two-year period.537 We compared the hourly 

gross heat rate data within each bin to the EGU’s benchmark 

value. Similar to the proposal, within each bin we assessed the 

 

537 As described below, we also conducted this regionalized 

approach using a benchmark based on the best hourly gross heat 

rate accounting for outliers during any one-year period. See the 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 
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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.538 We refer to this 

percentage improvement value as the “consistency factor,” 

because applying it results in values for heat rate that are 

more consistent with the EGU’s benchmark for that bin. In our 

proposal we evaluated the heat rate improvement that would 

result from applying consistency factors of 10, 20, 30, 40 and 

50 percent of the distance between those less-efficient hourly 

gross heat rate values and the benchmark. Using engineering 

judgment, we selected a consistency factor of 30 percent, which 

produced results comparable to those obtained using other 

approaches for analyzing heat rate. For our final analysis under 

this approach, we refined the consistency factor based on a 

statistical assessment of the overall variability of heat rate 

in that EGU’s region, as described in the GHG Mitigation 

Measures TSD.539 As in the proposal, we applied the consistency 

 

538 In the proposal, we used heat input values rather than gross 

heat rate values. See the GHG Mitigation Measures TSD supporting 

the final CPP for more details. 

539 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 
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factor to each bin of each EGU’s hourly gross heat rate data, 

and averaged the result across all bins in that EGU’s matrix. 

The net result was an improved gross heat rate reflecting what 

that EGU would have achieved between 2002 and 2012 if, under 

certain ambient temperature and capacity factor conditions, the 

EGU had improved its gross heat rate during less-efficient hours 

to be slightly more consistent with the relevant benchmark 

value. We then compared the improved gross heat rate for each 

EGU to its actual 2012 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 on average are at 

 

consistency factor is 37.1 percent. Conducting this analysis on 

a nationwide basis would have resulted in application of a 

consistency factor of 38.2 percent. As described below, we also 

conducted this regionalized approach using consistency factors 

determined based on one-year figures. See the GHG Mitigation 

Measures TSD supporting the final CPP for more details. 
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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.540 

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.541 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 

 

540 Conducting this analysis on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.0 percent. See the table in this section and the GHG 

Mitigation Measures TSD for the results of this approach using 

benchmarks and consistency factors based on one-year averages. 

541 As described below, we also conducted this regionalized 

approach using each EGU’s best one-year rolling average. See the 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 
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4.9 percent in the Eastern Interconnection, 2.6 percent in the 

Western Interconnection and 3.1 percent in the Texas 

Interconnection.542 

Our third and final approach, the “best annual performance 

under similar conditions” approach, combines aspects of the 

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 rate for each of the 168 ambient 

temperature-capacity factor bins.543 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 

 

542 Conducting this approach on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.6 percent. As described below, we also conducted this 

regionalized approach using one-year averages. See the GHG 

Mitigation Measures TSD supporting the final CPP for more 

details. 

543 As described below, we also conducted this approach using 

one-year averages for each EGU instead of two-year averages. See 

the GHG Mitigation Measures TSD supporting the final CPP for 

more details. 
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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.544

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.545

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 

 

544 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. 

545 The GHG Mitigation Measures TSD describes in more detail our 

rationale for using one- and two-year averaging periods in our 

analytical approaches and methodology as a whole. 
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estimate of the potential for heat rate improvements by EGUs in 

that region. Those values ranged from 4.3 to 6.9 percent in the 

Eastern Interconnection, from 2.1 to 4.7 percent in the Western 

Interconnection, and from 2.3 to 4.9 percent in the Texas 

Interconnection. In all three regions, the most conservative 

values were generated using the “efficiency and consistency 

improvements under similar conditions” approach with two-year 

averaging periods and consistency factors. As shown in Table 6, 

the values produced by that approach were the minimum values for 

each region produced by any of the three approaches: 

Table 6. Heat Rate Improvement Potential by Region and Averaging 

Period. 

Analytical approach 

Heat rate improvement potential 

(percent) 

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 a well-supported and 

conservative estimate of the potential heat rate improvements 

Formatted Table

Formatted Table
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(and accompanying reductions in CO2 emission rates) that EGUs can 

achieve on average through best practices and equipment upgrades 

is a 4.3-percent improvement in the Eastern Interconnection, a 

2.1-percent improvement in the Western Interconnection and a 

2.3-percent improvement in the Texas Interconnection. The 

decision to use these values as the building block 1 potential 

in each region is based on the weight of evidence that these are 

conservative values; for each region, each of the three 

analytical approaches in our methodology supports our 

determination that the heat rate improvement value we selected 

is achievable. Taken individually, each approach provides an 

independently reasonable estimate of the potential for heat rate 

improvement. Furthermore, as described in the GHG Mitigation 

Measures TSD, these approaches are conservative on even an 

individual basis because they do not account for the full extent 

of heat rate improvements available through additional equipment 

upgrades and best practices. Some EGUs may have faced 

difficulties achieving significant heat rate improvement in the 

past and EGU owners may feel they face challenges in the future. 

Nevertheless, our methodology as a whole indicates that, on 

average, coal-fired EGUs can at least achieve the percentage 

heat rate improvement selected for their region through 
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application of best practices and some of the available 

equipment upgrades. A more detailed discussion of the EPA’s 

analysis in determining the heat rate improvement potential for 

existing coal-fired EGUs may be found in the GHG Mitigation 

Measures TSD supporting the final CPP. 

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;546 only that these heat 

 

546 Examples of the many types of best practices and equipment 

upgrades available to coal-fired EGUs include adopting sliding 

pressure operation to reduce turbine throttling losses; 

installing intelligent sootblowing system software; upgrading 

the combustion control/optimization system; installing heat rate 

optimization software; installing a production cost optimization 

program that benchmarks plant thermal performance using 

historical plant data; establishing centralized remote 

monitoring centers with thermal performance software for 

monitoring heat rates systemwide; repairing steam and water 

leaks; automating steam system drains; performing an on-site 

performance appraisal to identify potential areas for improved 

performance; developing heat rate improvement procedures and 

training O&M staff on their use; aligning the cycle to isolate 

or capture high-energy fluid leakage from the steam cycle; 

repairing utility boiler air in-leakage; performing utility 

boiler chemical cleaning; installing condenser tube cleaning 

system; retubing condenser; repairing/upgrading flue gas 

desulfurization systems; cleaning air preheater coils; 

adjusting/replacing worn air heater seals; replacing corroded 

air heater baskets; replacing feed pump turbine steam seals; 

overhauling high pressure feedwater pumps; installing fan and 

pump variable speed/frequency drives; upgrading turbine steam 

seals; upgrading all turbine internals; and installing coal 

drying systems. These and additional heat rate improvement 

measures are discussed further in the GHG Mitigation Measures 

TSD for the CPP Final Rule. 
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rate improvements are achievable in the regions through a 

combination of these methods. As discussed in section V.C.3 

below, we believe that a single heat rate improvement goal for 

each region incorporating both best practices and upgrades, 

based on the 11 years of hourly heat rate data for 884 coalfired EGUs available to the EPA, is a reasonable approach that 

is supported by our analysis, and is particularly conservative 

given that it does not account for the full range of heat rate 

improvements achievable through additional equipment upgrades 

and best practices. 

The performance rates quantified in section VI, below, 

reflect the region-specific values for heat rate improvement. 

Although the performance rates are based on the least stringent 

overall performance rate determined to be reasonable for any 

region, and are thus based in part on the percentage heat rate 

improvement identified for the region, this rule does not itself 

require any specific EGU to implement measures resulting in a 

specific percentage heat rate improvement. Rather, the 

percentage heat rate improvement value is merely reflected in 

the CO2 emission performance rates and corresponding mass-based 

and rate-based state goals. Each state has the flexibility to 

develop a plan that achieves those CO2 performance rates or 
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emission goals by assigning the emission standards the state 

considers appropriate to its affected coal-fired EGUs. 

Similarly, depending on the content of the applicable plan, 

affected EGUs may achieve their emission standards through use 

of any of the building block measures described in this rule or 

any other measures permitted under the plan. 

b. Changes from the proposal. In the proposed rule, we 

determined that building block 1 measures could on average 

achieve a 6-percent heat rate improvement from coal-fired EGUs 

in the U.S. based on a 4-percent heat rate improvement from 

implementation of best practices and a 2-percent heat rate 

improvement from equipment upgrades. Based on comments received 

and refinements made to our methodology for determining 

potential heat rate improvement from the hourly gross heat rate 

dataset of 884 coal-fired EGUs, we have conducted our analysis 

on a regional basis and reduced the overall expected percent 

heat rate improvement for coal-fired EGUs to 4.3 percent in the 

Eastern Interconnection, 2.1 percent in the Western 

Interconnection, and 2.3 percent in the Texas Interconnection.547

These values reflect improvements achievable through both best 

 

547 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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practices and equipment upgrades because, as described above, we 

also no longer include a separate estimation of the potential 

heat rate improvement achievable solely through equipment 

upgrades. 

We received comments on our proposed statistical 

methodology for determining the CO2 emission reductions 

opportunities achievable by coal-fired EGUs through heat rate 

improvements. We have closely reviewed those comments and, for 

the final rule, have made refinements to our methodology, as 

described above and explained in more detail in the GHG 

Mitigation Measures TSD supporting the final CPP. 

In the final rule, the EPA extends the implementation 

deadline from 2020 to 2022. This additional time will be helpful 

to the states seeking to conduct more targeted analyses of the 

nature and extent of heat rate improvements that specific coalfired EGUs can make, considering specific recent improvements or 

upgrades, planned retirements of older coal-fired EGUs, and 

other relevant considerations. The extended deadline will also 

provide additional time to accommodate changes to heat rate 

monitoring methods at EGUs and for the installation of new 

pollution controls that comply with other rules, as discussed 

below in the summary of key comments. 
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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 

investment required to capture the technical potential for CO2
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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 GHG Mitigation Measures 

TSD supporting the final CPP.548 Depending on the balance between 

equipment upgrades and best practices, improving heat rate would 

even result in a net savings for some EGUs. 

Based on the analyses of technical potential and cost 

summarized above and in Chapter 2 of the GHG Mitigation Measures 

TSD, we find that heat rate improvements of 4.3, 2.1 and 2.3 

percent are reasonable and conservative estimates of what coalfired EGUs in the Eastern, Western and Texas Interconnections, 

respectively, can achieve at a reasonable cost. 

 

548 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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3. Response to key comments 

Many commenters said that the EPA should have 

subcategorized by EGU design or operating characteristics for 

purposes of evaluating potential heat rate improvements under 

building block 1. 

Several studies categorize EGUs broadly by capacity, 

thermodynamic cycle, fuel rank or other characteristics. We 

considered subcategorizing the EGUs by their design and fuel 

characteristics under building block 1. Although grouping by 

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 
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quantity of EGUs used to calculate each average, which would 

increase the influence of random and atypical variations in the 

data on the overall averages, and would thus decrease our 

confidence in the results. Furthermore, states are free to 

apportion reductions in a way that reflects any subcategories of 

their choosing when determining the emission standards for 

individual affected EGUs. For a more detailed explanation of our 

decision not to subcategorize for purposes of determining 

building block 1, see the GHG Mitigation Measures TSD supporting 

the final CPP. 

Many commenters told the EPA that EGUs already have 

undertaken significant efforts to operate efficiently to provide 

reliable electric service at the lowest reasonable cost; that 

they believe they cannot significantly improve heat rate; that 

best practice maintenance activities are performed on a daily 

basis, including during maintenance outages that allow for the 

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, 
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these commenters say they have expended considerable effort and 

resources to maintain peak boiler efficiency at all times and, 

therefore, the 6-percent heat rate improvement proposed for 

building block 1 is unreasonable to apply to EGUs across the 

board; the EPA should develop a rule that allows treatment of 

affected EGUs on a case-by-case basis. 

We commend the efforts of those who strive to operate and 

maintain EGUs in the best possible manner to minimize heat loss 

and CO2 emissions. This rule does allow for treatment of EGUs on 

a case-by-case basis. States may believe that individual 

considerations are appropriate in some cases and, accordingly, 

we have purposely allowed states to make decisions about how to 

implement specific CO2 reductions. Our determinations of 4.3-, 

2.1- and 2.3-percent heat rate improvement for EGUs in the 

Eastern, Western and Texas Interconnection, respectively, are 

conservatively based on the lowest value identified by any of 

our reasonable statistical analyses. If states choose to set 

limits on individual affected EGUs based in part on the 

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 
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EGUs complying with state requirements) can make case-by-case 

decisions about how to achieve goals does not contradict our 

conservative estimates -- which are based on millions of hours 

of operating data reported to the EPA by EGUs -- of how much 

EGUs are capable of improving their heat rate in each region 

overall. Opportunities to improve heat rate abound for affected 

EGUs as a whole, as evidenced by the fact that the approaches in 

our statistical methodology each included a comparison of an 

EGU’s historical heat rate to its 2012 heat rate. 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 
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(Eastern), 2.1 percent (Western) and 2.3 percent (Texas), as 

discussed above and described in detail in the GHG Mitigation 

Measures TSD supporting the final CPP. We expect that, on 

average, affected coal-fired EGUs can at a minimum improve heat 

rate in these amounts by implementing best practices and 

equipment upgrades identified in the GHG Mitigation Measures 

TSD. These overall heat rate improvement figures do not include 

an estimated percent heat rate improvement attributable 

specifically to upgrades. Although we are no longer including in 

our calculation of building block 1 a separate 2-percent heat 

rate improvement attributable solely to equipment upgrades, this 

decision is not because we believe that our initial 2-percent 

assessment of equipment upgrades was incorrect. To the contrary, 

the information presented in the S&L study was similar to that 

in other industry reports and studies -- many of which were 

referenced in the proposal TSD -- describing potential heat rate 

improvements at EGUs from all types of equipment upgrades. 

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 
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equipment upgrades, we conservatively set aside the entire 

additional 2 percent attributable solely to equipment upgrades. 

Accordingly, we determined the amount of potential heat rate 

improvement in the BSER solely from the heat rate analyses 

described above, which account for improvements through best 

practices and equipment upgrades that were at some point 

achieved by an EGU, but not for the full range of best practices 

and equipment upgrades that are actually available. 

Commenters also said that the EPA did not look at important 

factors that affect heat rate such as coal type, boiler type, 

cooling water temperature, age, nameplate capacity or the use of 

post-combustion pollution controls. 

Our statistical methodology compared each unit to its own 

historical performance and, therefore, largely accounts for the 

effects that a unit’s design or fuel characteristics would have 

on heat rate. As discussed above, our methodology used hourly 

data from 884 units over an 11-year period (2002-2012) and 

compared the variability in the heat rate of each individual 

unit to that unit’s own performance. By assessing potential heat 

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, 
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nameplate capacity, age, cooling water system, air pollution 

controls) on heat rate and heat rate variability. 

Although cooling water temperature likely plays an 

important role in a coal-fired EGU’s heat rate, as stated by 

commenters, there are no consistent quality-assured hourly 

cooling water temperature data available to the EPA. However, in 

an effort to determine the potential effect of cooling water 

temperature on heat rate, we looked at a sample of 45 coal-fired 

EGUs at 19 facilities for which we had hourly surface water 

temperature data (used as a surrogate for cooling water) from 

monitors located nearby and upstream of cooling water intake 

points. Our analysis found that surface water temperature did 

explain some of the variation in heat rate, but that surface 

water temperature is strongly correlated with ambient air 

temperature -- a variable we did control for in our methodology. 

Because of the strong correlation between ambient air 

temperature and surface water temperature, the availability of a 

comprehensive dataset of nationwide hourly ambient air 

temperature, and the similar explanatory power of surface water 

temperature and ambient air temperature, it is unlikely that 

separately addressing cooling water temperature would 

significantly change the results. Rather, we are confident that 
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our use of hourly ambient air temperature in our analyses 

adequately addressed any significant impact of cooling water 

temperature. See the GHG Mitigation Measures TSD supporting the 

final CPP for further details about this analysis. As described 

further in that TSD, the other potentially relevant variables 

for which we did not directly control are unlikely to 

significantly affect the average heat rate. 

Commenters said that the heat rate improvement attributable 

to upgrades will degrade over time or require repeated and 

costly further upgrades. 

We are aware that some heat rate improvement measures can 

degrade over time. Like most power plant components, some heat 

rate improvement technologies require maintenance in order to 

sustain their efficacy over time. Therefore, to avoid 

degradation, personnel at EGUs will need to diligently apply 

“best practices” on a regular basis, a practice that numerous 

commenters say is standard operating procedure. The S&L study 

includes estimates of associated O&M costs for each heat rate 

improvement method that is discussed. As we explained in the 

proposal, the related O&M costs of diligently applying best 

practices are relatively small compared to the associated 
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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 EPA’s analysis of heat rate improvement potential in the 

applicable region as a guide, while keeping in mind the CO2

emission performance rate. The final rule establishes a uniform 

national performance rate based on the least stringent regional 

performance rate calculated with the building blocks. 

Accordingly, affected EGUs in regions not setting the national 

level have emission reduction opportunities beyond those 

reflected in the applicable performance rate. For affected coalfired EGUs in the contiguous United States, a methodology that 

assesses potential heat rate improvement within each 
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interconnection reflects the regional nature of the 

interconnected electricity system and the region-wide scope of 

opportunities available for those EGUs to access emission 

reduction measures through emissions trading.549 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. 

We further note, along with some commenters, that sitespecific engineering studies or unit-by-unit analyses of heat 

rate improvement potential for coal-fired EGUs are not available 

to the EPA; only a small number of site-specific case studies 

are available in the public literature. We considered that for 

 

549 As described in section V.A and VI.D, affected EGUs in the 

isolated states and territories of Alaska, Hawaii, Puerto Rico, 

and Guam lack the same opportunities to access the building 

blocks across wide regions that affected EGUs in the contiguous 

states enjoy. For more details about these isolated states and 

territories, see the technical support document entitled, “CO2

Emission Performance Rate and Goal Computation TSD for Final 

Rule.” 
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the EPA to develop a comprehensive, unit-by-unit heat rate 

improvement study of nearly 900 coal-fired EGUs from scratch, it 

would likely cost the Agency $50,000 to $100,000 to study each 

EGU (almost $50 to $100 million total) and require three to four 

years to complete. Such a granular analysis would not serve the 

broader goal-setting purpose of this rulemaking. We agree with 

commenters who have pointed out that a heat rate improvementestimating effort of that magnitude and duration would be 

unnecessarily lengthy and expensive. Nor would such a granular 

analysis be a necessary predicate for states to develop emission 

standards, or for EGUs to comply with those emission standards. 

Rather, our methodology’s reliance on individualized, unit-byunit hourly performance data from 884 EGUs provides conservative 

and reasonable regional estimates of heat rate improvement 

potential. Indeed, given the conservative nature of our 

methodology, a unit-specific approach that evaluates the full 

range of best practices and equipment upgrades available at 

individual EGUs -- including upgrades not accounted for here -- 

would be more likely to result in higher overall heat rate 

improvement figures than we are finalizing for building block 1. 

Furthermore, site-specific information forms the foundation of 

the EPA’s estimated heat rate improvement potential, and similar 
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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 GHG Mitigation Measures TSD -- incorporates 

expected retirements of inefficient units and generation shifts 

away from using coal-fired EGUs as peaking units. 
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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 

opportunities to achieve the uniform performance rate through 

improvements in net heat rate alone. 
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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.550

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 

install approximately 18.6 GW of wet flue gas desulphurization 

 

550 See above for an explanation of gross versus net heat rate. 
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(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 2025.551 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 GHG 

Mitigation Measures TSD supporting the final CPP. 

Commenters contended that the 11 years of data used to 

evaluate potential heat rate improvement is too broad, and that 

 

551 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 population of domestic coal-fired EGUs has changed 

significantly over this time period. 

The 11-year span for the hourly gross heat rate data is 

appropriate because it represents a wide variety of economic 

conditions, market conditions and fleet composition, while also 

capturing the relatively recent historical performance of 

affected coal-fired EGUs. We also noted in the proposal TSD that 

the population of coal-fired EGUs used in the analytical 

approaches to determine potential heat rate improvement is made 

up of coal-fired EGUs that operated in 2012. The gross heat rate 

data of any coal-fired EGUs that retired prior to 2012 were not 

included in the dataset. 

Commenters stated that many of the changes in heat rate 

reflected in the 11-year hourly gross heat rate dataset are 

attributable to changes in monitoring methodology, and thus do 

not represent heat rate improvements attributable to best 

practices or equipment upgrades. In addition, commenters are 

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 
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flow where the monitoring and reference method measurements are 

taken, and which options under the Part 75 emission measurement 

rules are chosen in the application of the various flow rate 

reference methods. In general, more accurate stack gas flow 

monitoring methodologies yield lower values that, when used to 

calculate emissions or heat input, may lower the heat rate 

values reported to the EPA. 

Some EGUs adopted monitoring methodologies that have the 

potential to affect the exactness of the data we used for 

assessing heat rate improvements. However, as discussed in 

detail in the GHG Mitigation Measures TSD supporting the final 

CPP, our review of the data shows that a relatively small amount 

of the data are affected by these changes; we are confident that 

the values adopted for building block 1 are conservative and 

reasonable estimates of the potential for heat rate improvement 

in each region. 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 based on 2012 gross heat rate data, our results 

are unaffected by EGUs that used more accurate monitoring 

methodologies in 2012 or used the same monitoring methodologies 
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consistently throughout the 11-year study period. For these and 

other reasons discussed in detail in the GHG Mitigation Measures 

TSD, we remain confident in our results despite the marginal 

differences attributable to monitoring methodologies in some of 

the heat rate data for a subset of EGUs.552 

In terms of concerns with future methodological changes, 

the overwhelming majority of the 884 EGUs in the dataset we used 

to assess heat rate improvement have already changed their stack 

gas flow monitoring methodology in 2012 or earlier. Furthermore, 

extension of the compliance date to 2022 for this rule, as 

discussed above, more than adequately allows enough time for 

EGUs to determine how to actually improve their heat rates and 

lower CO2 emissions while accommodating future changes to 

monitoring methodologies. For a more detailed explanation, see 

the GHG Mitigation Measures TSD supporting the final CPP. 

Commenters said that there is no proof that lowering the 

heat rate will reduce variability or that reduced variability 

 

552 Furthermore, on a fundamental level, our methodology accounts 

for a certain amount of any residual inexactness because we have 

conservatively adopted the lowest value identified by any of our 

reasonable approaches -- all three of which are themselves 

conservative because they do not account for the full extent of 

heat rate improvements achievable through equipment upgrades. 
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will reduce heat rate, i.e., correlation does not prove 

causation. 

As an initial matter, it is important to note that for the 

final rule the EPA used three types of statistical analyses to 

evaluate and estimate potential heat rate improvements of coalfired EGUs, and only one of these analyses involved any 

consideration of heat rate variability. All three types of 

statistical analyses are described in the GHG Mitigation 

Measures TSD supporting the final CPP. 

These commenters are correct that, in the abstract, 

reducing heat rate variability only means that heat rate will be 

more consistent -- not necessarily lower or higher. However, our 

analysis is not an abstract evaluation of the potential to 

reduce variability, as commenters suggest, but rather is an 

evaluation of the potential heat rate improvement achievable 

through reducing variability -- i.e., reducing variability to 

achieve a more consistently low heat rate. See the more detailed 

discussion of the statistical procedures used for the final 

rule, above. In particular, the application of a “consistency 

factor” in the analyses performed for both the proposed and 

final rule demonstrates the potential results if each individual 

EGU operated slightly more consistently with the lower heat 
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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 the utility power sector’s own efforts to 

reduce variability, which are aimed at securing the economic 

benefits of a more consistently lower overall heat rate. 

Some commenters expressed concern that heat rate 

improvements could trigger applicability of new source review 

(NSR) provisions. The relationship of this final rule to other 

regulatory provisions, including NSR, is discussed in section X 

of the preamble. 

D. Building Block 2—Generation Shifts Among Affected EGUs 

The second element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which fossil 

steam EGUs can shift generation to existing NGCC EGUs. In this 

section, we define building block 2 as the gradual shifting of 

generation from existing fossil steam to existing NGCC within 

each region up to a maximum NGCC utilization of 75% on a net 

summer basis. In each year of the interim period, this 75% net 
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summer maximum potential is subject to a regional limit informed 

by historical growth rates. This section summarizes the EPA’s 

analysis supporting that definition, including a discussion of: 

historical trends in the utility power sector, the gradual 

phase-in governed by historical growth rates, the technical 

feasibility of utilizing existing NGCC units at 75% net summer 

capacity, historical availability of and generation shifts to 

NGCC units, reliability, natural gas infrastructure, natural gas 

production, transmissions planning and construction, regulatory 

flexibility, and cost-effectiveness of CO2 reductions. 

1. Demonstration of Ability to Reduce CO2 Emissions through 

Shifting Generation 

a. Background of utility power sector 

The ability to shift generation from higher- to loweremitting sources is compatible with the way EGUs are generally 

dispatched.553 The standard approach to dispatching generation is 

through Security Constrained Economic Dispatch (SCED), a wellestablished practice in the electric power industry.554 As the 

 

553 See Preamble, II.C.1, History of the Power Sector, for 

background to this discussion. 

554 “Economic Dispatch: Concepts, Practices and Issues”, FERC 

Staff Presentation to the Joint Board for the Study of Economic 

Dispatch”, Palm Springs, California, November 13, 2005. A copy 

of this presentation is available in the docket for this rule. 
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name indicates, SCED has two defining components: economic 

operation of generating facilities and assurance that the 

electric system remains reliable and secure.555 Economic dispatch 

generally refers to shorter-term planning and operations from a 

day ahead through real time. During this period, generating 

units are committed – a process known as “unit commitment,” in 

which units are committed to be ready to provide generation to 

the system when they will be needed – and then dispatched in 

real time to meet the electricity demand of the system. Overall 

changes in the level of generation from different facilities are 

also planned over time periods longer than this 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 

 

555 “Security Constrained Economic Dispatch: Definitions, 

Practices, Issues and Recommendations: A Report to Congress”, 

Federal Energy Regulatory Commission, July 31, 2006. 
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generation among different generation types to match longer-term 

requirements and goals. 

 EGUs using technologies with relatively low variable 

costs, such as nuclear units, are for economic reasons generally 

operated at their maximum output whenever they are available. 

Renewable EGUs such as wind and solar units also have low 

variable costs, but the magnitude and timing of their output 

generally depend on wind and sun conditions rather than the 

operators' discretion. In contrast, fossil fuel-fired EGUs have 

higher variable costs and are also relatively flexible to 

operate. Fossil fuel-fired EGUs are therefore generally the 

units that operators use to respond to intra-day and intra-week 

changes in demand. Because of these typical characteristics of 

the various EGU types, the primary opportunities for switching 

generation among existing units available to EGU owners and grid 

operators generally consist of opportunities to shift generation 

among various fossil fuel-fired units, in particular between 

coal-fired EGUs (as well as oil- and gas-fired steam EGUs) and 

NGCC units. In the short term — that is, over time intervals 

shorter than the time required to build a new electric 

generation unit — fossil fuel-fired units consequently tend to 

compete more with one another than with nuclear and renewable 
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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. 

b. Trends in generation shifts from coal-fired to natural 

gas-fired sources. Since at least 2000, fossil fuel-fired 

generation has been shifting from coal- and oil-fired EGUs to 

NGCC units, both as a result of construction of additional NGCC 

units, and also as a result of dispatch of pre-existing NGCC 

units at higher capacity factors. As a result, generation from 

NGCC EGUs in 2012 reached over four times the level of NGCC 

generation in 2000, while generation from coal and oil/gas steam 

EGUs decreased by around one third.556 As we demonstrate in the 

GHG Abatement Measures TSD, NGCC units are capable of operating 

at higher annual capacity factors than they have historically, 

so there remains considerable opportunity for increased use of 

existing NGCC units to replace generation currently supplied by 

higher-emitting coal and oil/gas steam units. The electric 

utility industry is thus well-positioned to address the 

requirements of this building block by increasing use of 

 

556 Ventyx Electric Power Database. 
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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 to retire coal 

capacity and add new NGCC. In the reference case without 111d, 

EIA forecasts 40 GW of coal retirements and 53 GW of NGCC 

additions from 2014 to 2030.557 An EPA review of state Integrated 

Resource Plans (IRPs) shows a pattern of shifting away from coal 

steam capacity to NGCC. For example, Ameren plans to add 600 MW 

of NGCC and convert two coal units and Duke plans to add 680 MW 

of NGCC and convert one coal unit. For further examples, see 

the IRP TSD. 

c. Mechanisms for dispatch shifts from coal-fired to 

natural gas-fired generation. There are a variety of patterns of 

ownership and operational control of EGUs; these ownership and 

operational structures influence how EGUs will respond to this 

building block. However, all owners and operators have the 

ability to comply by using this building block. In terms of 

ownership, investor-owned utilities (IOUs) serve about 75 

percent of the US population, while consumer-owned utilities 

serve the remaining 25 percent.558 In states that have 

 

557 Energy Information Administration, Annual Energy Outlook 2015 

reference case, ref2015.d021915a. 

558 Regulatory Assistance Project, Electricity Regulation in the US: A Guide, Page 9, March 2011. 
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maintained traditional regulation, IOUs are generally vertically 

integrated (owning generating capacity as well as transmission 

and distribution infrastructure), and the wholesale sales of 

these EGUs are regulated by the state; in states that have 

deregulated their retail service, ownership of the EGU is 

separated from ownership of transmission, and wholesale sales of 

generation are regulated by FERC. Consumer-owned utilities 

comprise municipal utilities, public utility districts of 

various types owned by government agencies, nonprofit 

cooperative entities (co-ops), and a number of other entities 

such as Native American Tribes. 

Operational control of the dispatch of power over the 

electricity grid is superimposed on this pattern of ownership. 

Prior to electricity restructuring, this dispatch was typically 

operated by major vertically-integrated utilities or by public 

power entities. Over the last 15 years, large portions of the 

power grid are now independently operated by Independent System 

Operators (ISOs) or Regional Transmission Operators (RTOs). 

These entities are regulated by FERC and dispatch power from 

multiple owners to meet the loads on the bulk power grid. 

The combination of multiple ownership and types of 

operational control adds to the complexity of electricity 
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dispatch, but all affected EGUs, regardless of ownership and 

type of control, can use this building block to comply with the 

final rule. The principal difference among the differing 

entities lies in the types of methods that are available for the 

affected EGU owner to bring about the shift in generation that 

will make use of this building block for compliance. There are 

several alternatives to accomplish this result: the owner of the 

higher-emitting affected EGU may also own, or have affiliates 

that own, lower emitting generation and thus reduce its own 

generation and use its control over these other EGUs to increase 

their generation; an EGU may be able to reduce its generation 

and buy replacement power from the market that is lower 

emitting; the EGU may be able to reduce its generation and 

procure generation from a separately-owned lower emitting EGU; 

or the EGU owner may be able to purchase an emissions credit. 

With the exception of emissions crediting (discussed further 

below), these alternatives will be available in states with 

either rate or mass-based state plans without any change in 

their general form. 

The potential to shift generation identified for this 

building block is entirely consistent with the existing economic 

dispatch protocols described above. State environmental policies 
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can shift generation in two ways. The first is operational 

restrictions, such as permit limits on the number of hours that 

an EGU can operate in order to limit emissions. The second is 

changes in the relative costs of generation among different 

types of EGUs related to pollution reduction measures. For 

example, a regulation that necessitates the use of a control 

technology that requires the application of a reagent in a 

certain kind of EGU will increase the variable cost of operating 

that plant, which in turn may reduce the amount of generation it 

is called upon to deliver to the grid through securityconstrained economic dispatch procedures. 

In an organized market, where the system operator 

dispatches units partly based upon costs, an electric power 

plant that experiences an increase in its variable costs will 

tend to operate less than it otherwise would have. For example, 

market-based pollution control programs require units to hold 

tradable allowances to authorize their emissions of a regulated 

pollutant. Such an allowance-holding requirement puts a price 

on the act of emitting the regulated pollutant, which increases 

the operating costs of units that emit that pollutant, and thus 

such units will be dispatched less than they otherwise would 

without such an allowance-holding requirement. The Regional 
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Greenhouse Gas Initiative (RGGI) is an example of a state 

program that has this effect. In the present rule, although 

shifts in the mix of generation to address the costs of 

pollution control can lead to higher electricity generating 

costs overall, the EPA analysis shows these costs to be modest 

and well below their associated benefits.559

 In the first alternative, many of the NGCC units are 

owned by the same companies or affiliates that also own steam 

units. In these cases, changes in EGU generation can be planned 

by the company or affiliate without the need to engage in 

separate market transactions with outside parties. Where the 

affected EGU owner is also the dispatch entity, as in most 

traditional market structures, the EGU owner will generally have 

operational control over the unit. Environmental conditions, 

such as compliance costs or limits on generation, can be 

factored in with fuel costs to determine when the unit is 

committed to be available, how the unit can be most efficiently 

cycled, and at what level the unit is dispatched. 

An analysis of generation data from steam and NGCC units in 

2012 shows that 77 percent of the steam generation occurred from 

an EGU that owned, or that had an affiliate that owned, NGCC 

 

559 See the Regulatory Impact Analysis. 

Commented [A15]: This reference is unclear 

Deleted: determining
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generation. 80 percent of the generation shift potential 

identified in this building block (increasing NGCC generation up 

to a 75 percent capacity factor on a net basis to replace steam 

generation) could occur among these entities that own (either 

directly or through affiliates) both steam and NGCC 

generation.560 These data show that most EGU generation relevant 

for this building block is produced by entities that own both 

steam and NGCC generation. 

Another alternative available to an affected EGU owner that 

does not also own NGCC generation is for the higher-emitting 

affected EGU to reduce its generation and purchase replacement 

power from the market. In organized markets such as RTOs, it is 

available through standard practice, because the owner impacts 

how its EGUs are dispatched based upon how it bids into the RTO 

market. In this case, the owner can exercise control over the 

levels of generation across units by when it offers generation 

to the market operator (the RTO or ISO), and the prices it bids 

for this generation. As in traditional economic dispatch by a 

utility, environmental conditions, compliance costs, or limits 

on generation can be incorporated by the owner into the 

 

560 SNL Energy. Data used with permission. Accessed May 2015. 
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determination of the cost-effective generation pattern of its 

EGUs. 

In regions with organized electricity markets (including, 

but not limited to, RTOs or ISOs), the various types of EGU 

owners of higher-emitting sources can reduce their generation, 

and any resulting deficit in generation on the system can be 

supplied from other EGUs in the region; for example, a coalfired unit can reduce generation that is then replaced through 

the operation of the market by generation from an NGCC unit, 

subject to dispatch by a regional operator to ensure the 

reliable delivery of the generation to loads within the region. 

To comply with this rule, higher-emitting steam units will need 

greater reductions relative to lower-emitting NGCC units which 

will, in turn, tend to raise steam unit costs compared to NGCC 

units. As a result, the bids that a steam unit provides a 

market operator will rise relative to NGCC units. This process 

of reducing generation from a higher-emitting unit will lead to 

substitution of lower-emitting generation. 

EGU owners that do not participate in an organized 

electricity market may nevertheless purchase power from the 

wholesale power market. Purchases in the wholesale power market 

can be spot purchases, which are typically general purchases of 
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system power supplied by the EGUs across a region, or contract 

purchases, which may have more provider-specific characteristics 

(such as specifying the type of unit that is providing the 

power). Purchases between EGUs through the wholesale power 

market will have similar emission-lowering properties as 

operation of the organized market discussed above, because 

dispatch in balancing areas outside RTOs and ISOs also follows a 

similar economic dispatch protocol that is informed by each 

unit’s production costs and environmental limitations. 

Under this alternative, the steam generators may, in 

effect, realize emission reductions from building block 2 simply 

by reducing their generation. Steam generators do not need to 

purchase replacement electricity as a prerequisite for realizing 

emission reductions from reducing their own generation because 

other generators already have an incentive to provide as much 

electricity as load-serving entities are willing to buy in order 

to satisfy electricity demand.561 As noted above, higher-emitting 

generation sources will have to incorporate correspondingly 

 

561 Some owners or operators of steam generators may have electricity supply obligations to which they may be 

applying power from those steam generators. However, such parties may fulfil those supply obligations using the 

wholesale power market in the exact same way described here that enables any other generator with economically 

attractive electricity to offer such supply. In other words, the ability of a steam generator to reduce its generation is 

not contingent on an associated purchase to replace that power, notwithstanding the possibility that the owner or 

operator of that steam unit may choose to make such a purchase to meet an electricity supply obligation. 
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higher costs of pollution reduction into their supply bids 

compared to lower-emitting generation sources, and as a result, 

load-serving entities will seek to buy a greater share of 

electricity from the lower-emitting sources because their supply 

bids will be more economically attractive. Once the steam 

generators reduce their generation (and associated emissions), 

the other entities in the electricity system arrange for the 

replacement electricity. The outcome of this power market 

process will reduce both the mass and the rate of emissions 

across sources. 

An owner of a source can also reduce the generation of an 

EGU by substituting generation from a lower-emitting NGCC 

directly. For an EGU owner without existing NGCC generation, 

this substitution can take the form of a bilateral contract 

purchase. In RTOs and ISOs, this alternative often takes the 

form of a contract for differences, where the replacement source 

could be an NGCC and the contract specifies a delivery location 

and the price of the power. In bilateral markets, the contract 

vehicle could be a Power Purchase Agreement from a replacement 

source. It is also possible that the owner of a steam unit 

could directly invest in an existing EGU by purchasing the asset 

or taking a partial ownership position, thus acquiring the 
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generation from the unit through that means. The acquired 

generation and its associated emissions could be used for 

compliance by the higher-emitting EGU, in accordance with the 

plan under which it is operating. The amount of generation that 

could be shifted using the approaches described in this 

paragraph will depend on the type and terms of the commercial 

arrangements, as well as the potential need for regulated 

entities to obtain approvals for contracts or for changes in 

asset positions. The wide range of approaches permitted by this 

rule provides flexibility, both within a year and across 

multiple years, for EGUs to fashion these arrangements to fit 

their circumstances. 

An EGU is also able to meet its reduction obligations using 

emission rate credits or allowances. The particular nature of 

this alternative will depend on how a state elects to develop 

its plan. If a state chooses a mass-based approach, the EGU 

would simply need to hold allowances to cover its emissions. To 

realize an emission reduction from building block 2 under this 

approach, a steam generator would only need to reduce its 

emissions by reducing its generation, which would lead to that 

generator needing fewer allowances to cover its emissions under 

Deleted: be
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the program. In a rate-based state, the state may choose to 

provide for compliance by purchasing tradable emission rate 

credits. To realize an emission reduction from building block 2 

under this approach, a steam generator would be able to adjust 

its effective emission rate by purchasing emission rate credits 

that are produced by other sources whose emission rates are 

lower than the applicable rate standard. In this fashion, a 

steam generator does not need to purchase lower-emitting 

replacement power per se in order to demonstrate an emission 

reduction from this building block; instead, the steam generator 

may purchase any emission rate credits that were produced from 

lower-emitting sources 

(see section VIII for more detail on how state plans can 

use an emission rate credit approach to facilitate a rate-based 

compliance demonstration of this type of emission reduction).562

 

562 Stakeholders have recognized that emission rate credits and 

allowances are an effective tool for EGUs to implement the 

building blocks and achieve their standards of performance 

required under this rule. See “Clean Power Plan Implementation: 

Single-State Compliance Approaches with Interstate Elements,” 

Georgetown Climate Center (May 2015), 

http://www.georgetownclimate.org/sites/www.georgetownclimate.org

/files/GCC_ComplianceApproacheswithInterstateElements_May2015.pd

f. 
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The approaches shown here collectively demonstrate that all 

steam generators -- regardless of size, location, form of 

ownership, or type of market in which they operate -- can 

implement building block 2 through some or all of the mechanisms 

described. 

2. Timing of Generation Shift 

The EPA received significant public comments expressing 

concern regarding the proposal’s incorporation of the full 

building block 2 shift in generation by the first year of the 

interim period. These commenters perceived this approach as 

requiring states to achieve such a significant portion of the 

required CO2 emission reductions early in the interim period that 

states would lack flexibility in when and how they may achieve 

the required emission reductions. Other commenters expressed 

concern that the full extent of building block 2 would be 

difficult for some states to achieve by the first year of the 

interim period as a result of technical, engineering, and 

infrastructure limitations or other considerations; that such 

timing may crowd out other cost-effective options for emission 

reductions; and that such timing might have negative 

implications for reliability. 
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In the proposal, the EPA determined that emission 

reductions are feasible and achievable at fossil fuel-fired 

steam EGUs by shifting from more carbon-intensive EGUs to less 

carbon-intensive EGUs, as part of the BSER. More specifically, 

the EPA proposed that generation shifts from fossil fuel-fired 

steam units (which are primarily coal-fired) to NGCC units, up 

to a utilization of 70 percent on a nameplate capacity basis, 

could be achieved by 2020. In contrast, the EPA proposed that 

reductions in CO2 emissions from fossil fuel-fired units 

associated with other measures, such as increased utilization of 

RE generating capacity and increased demand-side energy 

efficiency, would be achievable on a phased-in basis between 

2020 and 2029, reflecting the time needed for deployment.563 In 

light of the concerns noted above, the EPA solicited comment in 

the NODA on potential rationales for phasing in the potential to 

shift generation under building block 2.564

As described in section III of this preamble, the EPA has 

revised the interim compliance period to start in 2022, which 

itself is a meaningful response regarding the concerns expressed 

 

563 (79 FR 34866) 564 (79 FR 64543)
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by commenters about the timing of building block 2’s generation 

shift potential. In addition, the EPA has evaluated the 

feasibility over time of building block 2 within the framework 

of BSER, and is finalizing a change to building block 2 that 

gradually phases in the shift from existing fossil steam to 

existing NGCC over the interim period. This phase-in allows for 

additional time to complete potential infrastructure 

improvements (e.g., natural gas pipeline expansion or 

transmission improvements) that might be needed to support more 

use of existing natural gas-fired generation, and provides 

states with the increased ability to coordinate actions taken 

under building block 2 with actions taken under building block 3 

(deployment of new renewable capacity). 

The phase-in schedule applies a limit to the maximum 

building block 2 potential in each year of the interim period 

based on two parameters. The first parameter defines an amount 

of generation shift to existing NGCC capacity that is feasible 

by 2022, and the second parameter defines how quickly that 

amount could grow until the full amount of NGCC generation could 

be achieved as part of the BSER. Both of these parameters are 

determined by examining the extent to which gas-fired generation 

has increased over historical time periods. The first parameter 
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is based on the single largest annual increase in power sector 

gas-fired generation since 1990, which occurred between 2011 and 

2012 and is equal to 22 percent.565 We believe that this amount 

is a conservative estimate of the ability of the sector to 

increase utilization of NGCC capacity between now and 2022, 

given that this increase has already occurred in a single year. 

The second parameter is based on the average annual growth in 

gas-fired generation in the power sector between 1990 and 2012, 

which is approximately 5 percent per year. 

In the performance rate calculation methodology, these two 

parameters constrain the annual rate at which building block 2 

shifts generation from fossil steam units to NGCC units. The 

interim performance rate is an average of annual rates 

calculated over the 2022-2029 period. The two parameters above 

limit the extent to which NGCC generation is able to increase 

and replace fossil steam generation in each year of the interim 

period. In the first year, NGCC generation is limited to a 

maximum of a 22 percent increase from 2012 levels in each 

region. In each subsequent year, regional NGCC generation is 

 

565 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. 

Formatted: Highlight
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limited to a maximum of a 5 percent increase from the previous 

year. This phase-in continues in the performance rate-setting 

methodology until the full building block 2 level of shifting 

from fossil steam generation to NGCC generation is reached. 

Under this approach, building block 2 is completely phased into 

the source category calculation of all regions by the end of the 

interim period. 

NGCC Generation (TWh) 

Region 

Maximum 

Potential 

at 75% 

2012 

(adjusted) 

BSER Maximum 

2022 2023 2024 2025 2026 2027 2028 2029 2030 

Limit -- -- 22% 5% 5% 5% 5% 5% 5% 5% 5% 

Eastern 

Intercon

nection 

987 734 896 941 987 987 987 987 987 987 987 

Western 

Intercon

nection 

306 198 242 254 267 280 294 306 306 306 306 

Texas 

Intercon

nection 

204 137 167 176 185 194 203 204 204 204 204 

This phase-in, in addition to the flexible nature of the goals, 

ensures that the overall framework of this final rule includes 

sufficient flexibility, particularly with respect to timing of 

and strategies for reducing emissions from the affected units, 

so that states can develop cost-effective strategies and allow 

for infrastructure improvements to occur should they prove 

necessary in some locations. 

2. Basis for Magnitude of Generation Shift 

Formatted Table
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a. Technical feasibility of NGCC units to generate at 75% 

of their capacity. 

In order to estimate the potential magnitude of the 

opportunity to reduce power sector CO2 emissions through shifting 

generation among existing EGUs, the EPA first examined 

information on the design capabilities and availability of NGCC 

units. Availability is defined as the number of hours that 

generators are available to generate electricity, and it is 

typically expressed as a percentage of the total number of hours 

in a year. Since the value of NGCC capacity is related to how 

much electricity the owner of that capacity can generate and 

sell, units are typically designed with very high availability 

ratings. Baseload units have annual average availabilities of 

approximately 91%-92%, and peaking units are generally available 

96% to 98% of peak hours.566 The EPA also examined information 

on the historical availability of NGCC units in practice. This 

examination showed that, although most NGCC units have 

historically been operated in intermediate-duty roles for 

economic reasons, they are technically capable of operating in 

baseload roles at much higher annual utilization rates. Average 

 

566 Negotiating Availability Guarantees for Gas Turbine Plants, available at: http://www.powereng.com/articles/print/volume-105/issue-3/features/negotiating-availability-guarantees-for-gas-turbine-plants.html 
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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.567

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.568 These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal. Although the relative 

fuel prices vary by location, as do the recent generation 

 

567 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. 

568 http://www.eia.gov/todayinenergy/detail.cfm?id=6990. 
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patterns, this trend holds across broad regions of the U.S. In 

the aggregate, the historical data provide ample evidence 

indicating that, on average, existing NGCC units can achieve and 

sustain utilization rates higher than their historical average 

utilization rates. 

Utilization of EGUs is often considered using the metric of 

a capacity factor, which is the percentage of total production 

potential that an electric generating unit achieves in a given 

time period. A capacity factor of 75 percent thus represents a 

unit producing three-quarters of the electricity it could have 

produced in that time had it utilized its entire capacity. The 

EPA received multiple comments regarding the proposed use of 

nameplate capacity in calculating the potential utilization 

level of existing NGCCs under building block 2. These comments 

stated that net summer capacity is a more meaningful and 

reliable metric than nameplate capacity, because net capacity 

best reflects the electric output available to serve load. The 

EPA agrees with these comments. The quantification of building 

block 2 as well as performance rate and state goal calculations 

in the final rule are all based on net summer generating 

capacity. An annual utilization rate of 75 percent on a net 
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summer basis is similar to the proposed rule’s consideration of 

70 percent utilization on a nameplate basis.569 

The experience of relatively heavily-used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. 

The EPA reexamined the historical NGCC plant utilization 

rate data reported to the EIA, and found that in 2012 roughly 15 

percent of existing NGCC plants operated at annual utilization 

rates of 75 percent or higher on a net summer basis.570, In 

effect, these plants were providing baseload power. In addition 

to the 15 percent of NGCC plants that operated approximately at 

a 75 percent utilization rate on an annual basis, some NGCC 

plants operated at even higher utilization rates for shorter, 

but still sustained, periods of time in response to high 

cyclical demand. For example, on a seasonal basis, a significant 

number of NGCC plants have achieved utilization rates greater 

 

569 For a given amount of net generation, a net summer capacity factor appears 

higher compared to a corresponding nameplate capacity factor because net 

summer capacity reflects a lower amount of total generation potential 

achievable by the unit in practice. 570 Net summer capacity is defined as: “The maximum output, 

commonly expressed in megawatts (MW), that generating equipment 

can supply to system load, as demonstrated by a multi-hour test, 

at the time of summer peak demand (period of June 1 through 

September 30.) This output reflects a reduction in capacity due 

to electricity use for station service or auxiliaries.” (EIA, 

http://www.eia.gov/tools/glossary). 
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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. In 2012, roughly 10 percent of existing NGCC 

plants operated at annual utilization rates of 80 percent or 

higher on a net summer basis. While the EPA believes this level 

is also technically feasible on average for the existing NGCC 

fleet, the EPA is quantifying building block 2 assuming an NGCC 

utilization level of 75% on a net summer basis in order to offer 

sources additional compliance flexibility, given that the extent 
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to which they realize a utilization level beyond 75 percent will 

generate additional emission reductions and reduce the need for 

sources to rely on other emission reduction measures or building 

blocks. 

b. Historical generation shifts to NGCC. In 2012, total 

electric generation from existing NGCC units was 967 TWh.571 

After the application of the building block 2 potential 

(increasing NGCC utilization up to a 75 percent capacity factor 

on a net summer basis, including generation from NGCC units that 

were under construction in 2012), the total generation from 

these existing sources is assumed to be 1,497 TWh.572 

The EPA believes that producing this quantity of generation 

from this set of NGCC units is feasible. To put this level of 

generation into context, NGCC generation increased by 

approximately 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 16 percent higher than 2014 levelsThis reflects a 

smaller growth rate in potential NGCC generation between 2015 

 

571 Appendix 1, CO2 Emission Performance Rate and Goal Computation Technical Support Document for CPP Final 

Rule 

572 Appendix 1, CO2 Emission Performance Rate and Goal Computation Technical Support Document for CPP Final 

Rule 

Deleted: their
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and 2022 than has been observed in practice from 2005 to 2012, a 

time period of the same duration. 

c. Reliability. We also expect that an increase in NGCC 

generation of this amount would not impair power system 

reliability. Sources can achieve increases in utilization of 

existing NGCCs that displace generation from steam sources 

without impacting reliability because this shift in average 

annual utilization across existing EGUs does not inhibit the 

power sector’s ability to maintain adequate dispatchable 

resources to continue to meet reserve margins and maintain 

reliability. Furthermore, sources are not required to achieve 

the exact or even the full extent of the building block 2 

generation shift itself, which means that sources will have 

ample flexibility to maintain reliability-relevant operations 

while achieving emission reductions through a variety of 

measures.573

d. Natural Gas Infrastructure. The EPA also examined the 

technical capability of the natural gas supply and delivery 

system to provide increased quantities of natural gas and the 

capability of the electricity transmission system to accommodate 

 

573 See section VIII for further discussion of electric 

reliability planning. 
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shifting generation patterns. For several reasons, we conclude 

that these systems would be capable of supporting the degree of 

increased NGCC utilization potential in building block 2. First, 

the natural gas pipeline system is already supporting national 

average NGCC utilization rates of 60 percent or higher during 

peak hours, which are the hours when constraints on pipelines or 

electricity transmission networks are most likely to arise. NGCC 

unit utilization rates during the range of peak daytime hours 

from 10 a.m. to 9 p.m. are typically 15 to 20 percentage points 

above their average utilization rates (which have recently been 

in the range of 40 to 50 percent).574 Fleet-wide combined-cycle 

average monthly utilization rates have reached 65 percent,575

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 

 

574 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). 

575 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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be possible in other hours when constraints are typically less 

severe, and be reliably sustained for other months of the year. 

Furthermore, the NGCC utilization increase assumed in building 

block 2 could occur without a significant impact on peak demand 

for natural gas, including winter demand (when the power 

sector’s demand for natural gas competes with other sectors’ 

demands for natural gas), since increasing annual utilization of 

NGCCs could focus on non-peak periods when NGCC capacity factors 

are currently low. 

The second consideration supporting a conclusion regarding 

the adequacy of the gas supply infrastructure is that pipeline 

and transmission planners have repeatedly demonstrated the 

ability to methodically relieve bottlenecks and expand 

capacity.576 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 

 

576 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, the pipeline industry 

projected that increases of up to 30 percent in total 

deliverability out of the pipeline system would be possible.577

There have been notable pipeline capacity expansions over the 

past five years, and substantial additional pipeline expansions 

are currently under construction.578 Similarly, the electric 

transmission system is undergoing substantial expansion.579

 

577 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. 

578 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. 

579 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

approximately $60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). Construction of transmission lines 

of 345KV and above are generally major projects that are 

particularly effective at carrying power of large distances. 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 
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Further, the phasing in of building block 2’s potential in the 

determination of the BSER; the flexible nature of multi-year 

compliance with the ultimate emission reduction requirements of 

the rule; and the seven years between finalization of this rule 

and the first year of compliance provide time for infrastructure 

improvements to occur should they prove necessary in some 

locations. Combining these factors of currently observed average 

monthly NGCC utilization rates of up to 65 percent, the 

flexibility of the emission guidelines, the rates of historical 

growth, and the availability of time to address any existing 

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 capacity factor 

of 75 percent on a net summer basis. 

e. Natural Gas Production. We recognize that an increase 

in NGCC utilization rates at existing units corresponds with an 

associated increase in natural gas production, consistent with 

the current trends in the natural gas industry. The EPA expects 

the growth in NGCC generation assumed for building block 2 to be 

feasible and consistent with the production potential of 
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domestic natural gas supplies. Increases in the natural gas 

resource base have led to fundamental changes in the outlook for 

natural gas. There is general agreement that recoverable natural 

gas resources will be substantially higher for the foreseeable 

future than previously anticipated, exerting downward pressure 

on natural gas prices. According to EIA, proven natural gas 

reserves have doubled between 2000 and 2012. Domestic dry gas 

production has increased by 25 percent over that same timeframe 

(from 19.2 TCF in 2000 to 24.0 TCF in 2012). EIA’s Annual Energy 

Outlook for 2015 projects that production will further increase 

to 29.5 TCF by 2022 and 33 TCF by 2030, as a result of increased 

supplies and favorable market conditions. In the AEO 2015 high 

oil and gas resource case, production is projected to increase 

to 42.7 TCF in 2030. For comparison, building block 2 assumes 

NGCC generation growth of 235 TWh from 2012 to reach the level 

assumed for 2022 , and that NGCC generation growth would result 

in increased gas consumption of less than 2 TCF for the 

electricity sector, which is less than EIA’s projected increase 

in natural gas production of 5.5 TCF from 2012 to 2022. 

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). 
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IPM is a multi-regional, dynamic, deterministic linear 

programming model of the U.S. electric power sector that the EPA 

has used for over two decades to evaluate the economic and 

emission impacts of prospective environmental policies. To 

inform its projections of least-cost capacity expansion and 

electricity dispatch, IPM incorporates representations of 

constraints related to fuel supply, bulk power transmission 

capacity, and unit availability. The model includes a detailed 

representation of the natural gas pipeline network and the 

capability to project economic expansion of that network based 

on pipeline load factors. At the EGU level, IPM includes 

detailed representations of key operational limitations such as 

turn-down constraints, which are designed to account for the 

cycling capabilities of EGUs to ensure that the model properly 

reflects the distinct operating characteristics of peaking, 

cycling, and base load units. 

As described in more detail below, the EPA used IPM to 

assess the costs of increasing generation from existing NGCC 

capacity. IPM was able to meet average NGCC utilization rates of 

75 percent on a net summer basis, while observing the market, 

technical, and regulatory constraints represented in the model. 

This modeling also demonstrates the ability of domestic natural 
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gas supplies to increase their production levels, and deliver 

that supply through the pipeline network, to support the level 

of NGCC generation quantified in building block 2. Such a 

result is consistent with the EPA's determination that 

increasing the average utilization rate of existing NGCC units 

to 75 percent would be technically feasible. 

f. Transmission Planning and Construction. Achieving the 

generation shift quantified in building block 2 would not impose 

significant additional burden on the transmission planning 

process and does not necessitate major construction projects. 

Two considerations are important for this conclusion: 

First, building block 2 applies only to increases in 

generation at existing NGCC facilities and does not contemplate 

any connection of new capacity to the bulk power grid. Second, 

regional grids are already supporting operation of the NGCC 

units for sustained periods of time at the capacity factors 

quantified in building block 2.580 Although some upgrades to the 

grid (including potential, but modest, expansions of 

transmission capacity) may be necessary to support the extension 

of the time that these capacity factors are sustained over the 

course of the annual time period on which building block 2 is 

 

580 See Greenhouse Gas Abatement Measures TSD for a discussion of regional NGCC capacity factors. 
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based,, such upgrades are part of the normal planning process 

around the increased use of existing facilities. Consequently, 

EPA does not believe that achieving the generation shift 

potential in building block 2 would necessitate any significant 

additional requirements for transmission planning and 

construction beyond those already being addressed at routine 

intervals by the power sector. Furthermore, the phasing in of 

building block 2’s potential in the determination of the BSER; 

the flexible nature of multi-year compliance with the ultimate 

emission reduction requirements of the rule; and the seven years 

between finalization of this rule and the first year of 

compliance all provide time for infrastructure improvements to 

occur should they prove necessary in some locations. 

g. Regulatory Flexibility. The final consideration 

supporting our view that natural gas and electricity system 

infrastructure would be capable of supporting increased NGCC 

unit utilization rates at a maximum of 75% on a net summer basis 

is the substantial unit-level compliance flexibility of the 

emission guidelines. The final rule does not require any 

particular NGCC unit to achieve any particular utilization rate 

in any specific hour or year. Thus, even if isolated natural gas 
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or electricity system constraints were to limit NGCC unit 

utilization rates in certain locations in certain hours, this 

would not prevent an increase in NGCC generation overall across 

a state or broader region and across all hours on the order 

assumed in the generation shift potential quantified for 

building block 2. 

4. Cost 

Having established the technical feasibility and 

quantification of the potential to replace incremental 

generation at higher-emitting EGUs with generation at NGCC 

facilities as a CO2 emissions reduction strategy, we next turn to 

the question of cost. The cost of the power sector CO2 emission 

reductions that can be achieved through shifting generation 

among existing fossil fuel-fired EGUs depends on the relative 

variable costs of electricity production at EGUs with different 

degrees of carbon intensity. These variable costs are driven by 

the EGUs' respective fuel costs and by the efficiencies with 

which they can convert fuel to electricity (i.e., their heat 

rates). Historically, natural gas has had a higher cost per unit 

of energy content (e.g., MMBtu) than coal in most locations, but 
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for NGCC units this disadvantage in fuel cost per MMBtu relative 

to coal-fired EGUs is typically offset in significant part, and 

sometimes completely, by a technological heat rate advantage. 

To consider the cost implications of building block 2, the 

EPA expanded upon the proposal’s extensive analysis of the 

magnitude and cost of CO2 emission reductions through generation 

shifting within defined areas (consistent with the application 

of building blocks for performance rate- and state goalsetting), without consideration of the availability of other 

emission reduction ultimately available to units for compliance. 

To evaluate how EGU owners and grid operators could respond 

to a state plan's possible requirements, signals, or incentives 

to shift generation from more carbon-intensive to less carbonintensive EGUs, the EPA analyzed a series of scenarios in which 

the fleet of NGCC units within each of the regions considered 

for quantifying BSER (i.e., the three interconnections) was 

directed to achieve a specified average annual utilization rate 

across that region on a net basis while maintaining a fixed 

level of aggregate generation in that region across all existing 

fossil fuel-fired sources. The EPA conducted such scenarios to 

address average utilization rates of 70 percent, 75 percent and 

80 percent on a net basis, allowing for shifting of fossil 
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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. 

The costs of the various scenarios were evaluated by 

comparing the total costs and emissions from each scenario to 

the costs and emissions from a base case scenario. For the 

scenario reflecting a 75 percent NGCC utilization rate on a net 

basis with regional fossil generation shifting, comparison to 

the base case indicates that the average cost of the CO2

reductions achieved over the 2022-2030 period was $27 per metric 

ton of CO2. We view these estimated costs as reasonable and 

therefore as supporting the use of a 75 percent net utilization 

rate target for purposes of quantifying the emission reductions 

achievable at a reasonable cost through the application of 

building block 2 in the BSER. 

We also conclude from these analyses that potential impacts 

to fuel prices and electricity prices from achieving the extent 

of fossil generation shifting quantified for this building block 

are reasonably within the bounds of power sector experience. For 
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example, in the 75 percent NGCC unit utilization rate scenario 

where generation shifting is limited to regional boundaries, the 

delivered natural gas price was projected to increase by an 

average of 7 percent over the 2022-2030 period, which is well 

within the range of historical natural gas price variability.581

Projected wholesale electricity price increases over the same 

period were less than 4 percent, which similarly is well within 

the range of historical electric price variability. These 

projected impacts on prices were captured in the emission 

reduction costs of these scenarios already described above, 

which are reasonable and support use of a 75 percent NGCC 

utilization rate target for purposes of quantifying the emission 

reductions achievable through application of the BSER. 

However, we also note that the costs (and their 

incorporated price impacts) just described are higher than we 

would expect to actually occur in real-world compliance with the 

final rule’s compliance requirements for the following reasons. 

First, this analysis does not capture the building block 2 

phase-in, which assumes an average utilization rate over the 

interim period of less than 75 percent in all three 

 

581 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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interconnections. Second, the analysis overstates the extent to 

which building block 2 is ultimately reflected in the source 

category performance rates. While the performance rate 

computation procedure assumes a maximum NGCC utilization rate of 

75 percent on a net summer basis, the Eastern Interconnection’s 

realization of this level of NGCC utilization yields higher 

source category performance rates for steam than what would have 

been calculated for units in the Western Interconnection and 

Texas Interconnection if they realized that maximum NGCC 

utilization rate in conjunction with the other building blocks. 

In other words, there is substantial building block 2 potential 

in the Western Interconnection and Texas Interconnection that is 

not actually captured in the source category performance rates 

that are ultimately assigned to steam through this rate- and 

goal-setting approach (where the performance rates are 

ultimately determined by the BSER region with the highest rate 

outcome in the calculation). Therefore, the building block 2 

analysis overstates the cost of this component of BSER to the 

extent that it assumes achievement of this generation shift 

potential that is not reflected in the source category 

performance rates ultimately determined. Third, as a practical 

matter, sources will be able to achieve additional emission 
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reductions through other measures that may prove to be less 

costly than generation shifting and could substitute for the 

reductions and costs considered here. These building block 2 

analyses were focused on evaluating the potential impacts of 

fossil generation shifting in isolation, and as a result, they 

do not consider states’ and sources’ flexibility to choose among 

alternative CO2 reduction strategies that could offer lower-cost 

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 rule. This 

section summarizes some of these comments, and the remainder of 
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the comments are responded to in the Response to Comment 

document, available in the docket. 

The EPA received comment regarding the potential for an 

increase in upstream methane emissions from increased 

utilization of natural gas. Our analysis found that the net 

upstream methane emissions from natural gas systems and coal 

mines and CO2 emissions from flaring of methane will likely 

decrease under the Clean Power Plan. Furthermore, the changes in 

upstream methane emissions are small relative to the changes in 

direct emissions from power plants. The technical details 

supporting this analysis can be found in the Regulatory Impact 

Analysis. 

Commenters also expressed concern that neither a utility 

nor any state agency controls dispatch in most states. The EPA 

believes these comments fail to adequately appreciate that the 

utilities do control the dispatch of units that they own and/or 

operate, either by being the actual dispatch agent in many cases 

where there is no RTO or ISO that schedules the dispatch, or by 

the choice of units and bids they offer into an organized 

electricity market operated by an RTO or ISO. These entities 

currently control the dispatch of their units while respecting 
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all existing requirements from environmental rules. This final 

rule does not change these current circumstances and makes clear 

that it is the EGU that is responsible for meeting the 

requirements in the state plan; the state is responsible for the 

development of that plan, but the state does not need to control 

the dispatch. 

Other comments object to the use of a single capacity 

factor for all existing NGCCs to quantify building block 2 

potential on the grounds that not all units may be able to 

achieve this utilization level, and that some units may be 

designed for cycling and so may need upgrades to sustain such 

utilization. The EPA disagrees with these comments. The 75 

percent capacity factor establishes a regional potential for 

generation from existing NGCC capacity, and it does not 

establish any individual unit requirements. 

E. Building Block 3 — New Zero-emitting Renewable Generating 

Capacity 

 The third element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which generation 

at the affected EGUs can be replaced by using an expanded amount 
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of zero-emitting renewable electricity generating capacity 

(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 methods by which 

affected EGUs of all types can increase the deployment of 

incremental amounts 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, the 

feasibility of deploying incremental amounts of RE 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 

push to commercialize RE more broadly began in the 1970s.582

Following a series of energy crises, new federal organizations 

and initiatives were established to coordinate energy policy and 

 

582 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. 
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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.583 

 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.584 In addition, since 1992, federal tax 

policy has provided important financial support via tax credits 

for the production of RE and investments in RE. 

 States have also taken a significant lead in requiring the 

development of RE resources. In particular, a number of states 

have adopted renewable portfolio standards (RPS), which are 

regulatory mandates to increase production of RE. As of 2013, 29 

states and the District of Columbia have enforceable RPS or 

 

583 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. 

584 “Restructuring or Deregulation?" Smithsonian Museum of 

American History. Accessed March 2015. Available at: 

http://americanhistory.si.edu/powering/dereg/dereg1.htm. 

Formatted: English (United States)
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similar laws.585 These RPS requirements continue to drive robust 

near-term growth of non-hydropower RE. 

2. Trends in RE Development 

Today, RE is tightly integrated with the utility power 

sector in multiple ways: states have set RE targets for 

electrical load serving entities; utilities themselves are 

diversifying their portfolios by contracting with RE generators; 

and new RE generators are being developed to provide more 

electrical power grid support services beyond just energy (e.g., 

modern electronics allow wind turbines to provide voltage and 

reactive power control at all times).586,587

 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 2005.588 In 2013, U.S. non-

 

585 Energy Information Administration, Annual Energy Outlook 2014 

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

586 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. 

587 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. p. 107. 

588 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, 

Formatted: English (United States)
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hydro RE capacity for the total electric power industry exceeded 

80,000 MW, reflecting a fivefold increase in just 15 years.589 In 

particular, there has been substantial growth in the wind and 

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

U.S. wind generation has tripled and solar generation has grown 

twentyfold.590 

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

billion per year by 2030.591 RE growth is further spurred by the 

significant amount of existing natural resources that can 

support RE production in the United States.592 In the Energy 

Information Administration’s Annual Energy Outlook 2015, RE 

generation grows substantially from 2013 to 2040 in the 

 

Table 7.2b, Available at: 

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

589 Non-hydro RE capacity for the total electric power industry 

was more than 16,000 megawatts (MW) in 1998. Energy Information 

Administration, 1990-2013 Existing Nameplate and Net Summer 

Capacity by Energy Source Producer Type and State (EIA-860), 

Available at: http://www.eia.gov/electricity/data/state/. 

590 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b. Available at: 

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

591 “Global Renewable Energy Market Outlook.” Bloomberg New 

Energy Finance, November 16, 2011, Available at: 

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

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

Technical Potentials: A GIS-Based Analysis,’’ (July 2012). 
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reference case and all alternative cases.593 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.594 

 The recent and projected growth of RE is in part a 

reflection of its increasing economic competitiveness. Numerous 

studies have tracked capital cost reductions and performance 

improvements for RE, particularly for solar and wind. Analyses 

of wind’s competitiveness found falling wind turbine prices and 

downward trends in levelized cost of energy estimates in recent 

years while the wind industry developed lower wind speed sites 

with new turbine designs (e.g., increased turbine hub heights 

and rotor diameters). Performance improvements have come from 

novel deployments of new turbines designed for lower quality 

wind sites that are deployed at higher quality wind sites, which 

have resulted in capacity factor increases for these 

 

593 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. 25. 

594 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6-7. 
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locations.595596 For utility-scale solar, cost and performance 

have also improved significantly. Analysis has shown that the 

installed price of solar photovoltaics (PV) systems, prior to 

any incentives, has declined substantially since 1998. Capacityweighted average prices of solar PV in utility-scale deployments 

were 40 percent lower in 2013 than five years earlier.597598

Initially, price declines were partially driven by oversupply 

and manufacturers’ thin margins, but, in 2014, prices have 

remained low due to reductions in manufacturing costs.599 The 

capacity factors of new utility-scale installations have 

increased as systems are optimized to maximize energy 

production. For example, a growing number of utility-scale PV 

systems are increasing the direct current capacity of the solar 

 

595 “2013 Wind Technologies Market Report,” LBNL, August 2014. 

Available at: http://emp.lbl.gov/publications/2013-windtechnologies-market-report.

596 “2013 Cost of Wind Energy Review,” NREL, Feb 2015. Available 

at: http://www.nrel.gov/docs/fy15osti/63267.pdf. 

597 “Tracking the Sun VII” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/tracking-sun-vii-historicalsummary-installed-price-photovoltaics-united-states-1998-20.

598 “Photovoltaic System Pricing Trends,” NREL, 22 Sept 2014. 

Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf. 599 “Revolution Now – The Future Arrives for Four Clean Energy 

Technologies – 2014 Update,” DOE, Oct 2014. Available at: 

http://energy.gov/sites/prod/files/2014/10/f18/revolution_now_ 

updated_charts_and_text_october_2014_1.pdf. 
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array relative to the alternating current rating of the array’s 

inverter to increase energy production and improve project 

economics.600 The cost and performance improvements for wind and 

solar are driven by increased scale of production, improved 

technologies, and advancements in system deployments. 

3. Importance of Increasing Use of RE 

Currently, the utility power sector accounts for 40 percent 

of total annual energy consumption in the U.S.601 Introducing 

more zero-emitting RE generation over the long term could 

significantly reduce CO2 emissions, as production of RE 

predominantly replaces fossil fuel-fired generation and thereby 

avoids the emissions from that replaced generation. 

 A number of studies and recent policy developments have 

acknowledged RE as an important means of achieving CO2

reductions. California cited the reduction of CO2 emissions from 

electrical generations as one of the reasons for increasing its 

RE target from 20 percent to 33 percent by 2020 (and potentially 

 

600 “Utility-Scale Solar 2013,” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/utility-scale-solar-2013-

empirical-analysis-project-cost-performance-and-pricing-trends 

601 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. 

Formatted: English (United States)
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50 percent by 2030).602 A recent IPCC report also concluded that 

RE has large potential to mitigate CO2 emissions.603

 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.604

Increasing RE use will also continue to lower other air 

pollutants (e.g., fine particles, ground-level ozone, etc.), 

diversify energy supply, hedge against fossil fuel price 

increases and create economic development and jobs in 

manufacturing, installation, and other sectors of the economy. 

4. Access to RE by Owners of Affected EGUs 

 

602 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.

603 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. 

604 EPA, Water Resource Use. Accessed on March 2015. Available 

at: http://www.epa.gov/cleanenergy/energy-and-you/affect/waterresource.html. 

Formatted: Font: Times New Roman, Complex Script Font:

10 pt

Formatted: English (United States)
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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.605

Consequently, the EPA believes that an increase in RE is a 

proven way to reduce CO2 emissions at affected EGUs of all types 

at a reasonable cost. 

Owners and operators of affected EGUs across the U.S. 

already have substantial opportunities to procure RE regardless 

of their organizational structure and/or business model. In many 

parts of the country, EGUs are owned and operated by vertically 

integrated utilities. These utilities can be investor-owned 

utilities that operate under traditional electricity regulation, 

municipal utilities (munis), or electric cooperatives (co-ops). 

These utilities have significant control over the types of 

generating capacity they develop or acquire, and over the 

electricity mix used to meet demand within their service 

territories. 

Even when EGU owners participating in organized markets do 

not directly determine dispatch among energy sources, such EGU 

 

605 Refer to GHG Abatement Measures TSD for additional ownership 

statistics. 
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owners make decisions about what types of capacity they choose 

to develop and thus what generation mix they can ultimately 

supply into that market’s dispatch choices. Because zeroemitting RE technologies have relatively low variable costs, an 

EGU owner’s decision to install (or to finance the installation 

of) RE capacity will yield lower-cost electricity generation 

that, when available, a system dispatcher will prefer over 

higher-variable-cost generation from fossil fuel-fired capacity. 

Therefore, all owners of affected EGUs have a direct path for 

replacing higher-emitting generation with RE regardless of their 

organizational type and regardless of whether they operate in a 

cost-of-service framework or in a competitive, organized market. 

Many affected EGUs have already directly invested in RE. Of 

the 404 entities that owned part of at least one affected EGU 

under this rule, 178 also owned RE (biomass, geothermal, solar, 

water or wind). These 178 owners owned 82 percent of affected 

EGU capacity. As a whole, these entities’ share of RE capacity 

was equal to 25 percent of the total of their affected EGU 

capacity.606

Some of the largest owners of affected EGUs also owned RE 

(see Table 7). For example, NRG Energy, Inc. owns more than 

 

606 SNL Energy. Data used with permission. June 9, 2015 version.. 
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3,000 MW of RE capacity, over 20 percent of which (nearly 800 

MW) is solar, and almost 80 percent of which (over 2,500 MW) is 

wind. 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.607

Table [7] lists a sampling of affected EGUs that have large 

amounts of fossil fuel-fired capacity and RE capacity: 

 

TABLE 7. Sample of Owners of Affected EGUs and RE Capacity.608609 

Ultimate Parent Affected EGU 

Capacity (MW)

Renewable 

Capacity (MW)

NRG Energy, Inc. 48,787 3,149

Duke Energy Corporation 39,028 5,526

Southern Company 37,168 3,245

American Electric Power 

Company, Inc. 

34,940 1,142

NextEra Energy, Inc. 29,471 11,626

Calpine Corporation 23,878 1,509

Tennessee Valley Authority 21,717 5,427

Berkshire Hathaway Inc. 18,899 6,650

FirstEnergy Corp. 16,175 1,371

Exelon Corporation 10,283 3,361

Basin Electric Power 

Cooperative 

1,526 275

Nebraska Public Power 

District 

2,003 90

 

607 Ibid. 608 SNL Energy. Data used with permission. June 9, 2015 version. 609 eGRID, EPA. 2012 Unit-Level Data Using the eGRID Methodology. 

June 7, 2015 version.

Formatted Table
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American Municipal Power, 

Inc. 

1,112 53

Sacramento Municipal Utility 

District 

925 834

Golden Spread Electric 

Cooperative, Inc. 

521 78

 Large vertically integrated utilities generally have 

multiple options for investing in RE, including building their 

own RE capacity or procuring RE under a long-term power purchase 

agreement. Municipal utilities and rural cooperatives that own 

generating asset portfolios, particularly generation and 

transmission cooperatives and larger municipal utilities, have 

also used RE to reduce carbon emissions. Large generation and 

transmission cooperatives also purchase significant quantities 

of RE for their members. Federal power authorities own or 

contract significant amounts of RE.610,611

The list of the ten largest electric utilities with wind 

power capacity on the system (owned or under contract) includes 

a variety of affected EGU organizational structures, including 

vertically integrated investor-owned utilities, municipal 

 

610 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. 

611 Solar Energy Industries Association. Comments to the EPA and 

States on the Proposed Clean Power Plan Regulating Existing 

Power Plants 

Under Section 111(d) of the Clean Air Act. pp. 98-147. 
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utilities, and federal power authorities. Xcel Energy and 

Berkshire Hathaway Energy rank first and second 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.612

Many affected EGUs are already planning on deploying 

significant amounts of RE according to their integrated resource 

plans (IRPs). Electric utilities use IRPs to plan operations and 

investments over long time horizons. These plans typically cover 

10 to 20 years and are mandated by public utility commissions 

(PUCs). A recent study of IRPs, included in the docket for this 

rulemaking, shows this trend. For instance, Dominion plans for 

over 800 MW of wind and solar in their 2015 to 2029 planning 

period.613 Ameren is planning to retire one-third of the coal 

 

612 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=. The ten largest electric utilities with wind 

power capacity on the system (owner or under contract) includes: 

Basin Electric Power Cooperative; Associated Electric Coop; 

Great River Energy; Western Farmers Electric Coop; Minnkota 

Power Coop; Golden Spread Electric Cooperative; Old Dominion 

Electric Coop; Sunflower Electric Power Corp; Arkansas Electric 

Cooperative Corp; and Central Iowa Power Cooperative. 

613 Dominion North Carolina Power's and Dominion Virginia Power's 

Report of Its Integrated Resource Plan, August 2014, Available 

at: 
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generating capacity, as well as installing an additional 400 MW 

of wind, 445 MW of solar, and 28 MW of hydroelectric.614 [cite 

IRP TSD]. 

 

Independent power producers (IPPs) also can and do own both 

RE and fossil generation. For example, NRG is a diversified IPP 

that operates substantial coal, natural gas, wind, solar, and 

nuclear capacity. NRG demonstrates the ability of IPPs to reduce 

utilization of fossil fuel-fired EGUs and replace that 

generation with RE. NRG announced a goal to cut CO2 emissions 

from its fleet by 50 percent by 2030 (from a 2014 baseline). NRG 

has already reduced CO2 emissions from its fleet by 40 percent 

since 2005. This achievement demonstrates that when an IPP 

commits to shifting its generation portfolio, it can do so at 

reasonable cost and without reliability impacts. The NRG example 

shows that reduced utilization of fossil fuel-fired EGUs that is 

replaced by RE also owned by the EGU owner is adequately 

demonstrated. 

 

https://www.dom.com/library/domcom/pdfs/corporate/integratedresource-planning/nc-irp-2014.pdf 614 Integrated Resource Plan Update, October 2014, Available at: 

https://www.ameren.com/missouri/environment/renewables/amerenmissouri-irp
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EGU owners can also replace fossil fuel-fired generation 

with RE through bilateral contracts and renewable energy 

certificate (REC) purchases, as described below. Both the 

bilateral market for RE contracts and REC markets are well 

developed. There are no legal or technical obstacles to a fossil 

fuel-fired EGU owner acting as the counterparty of a bilateral 

contract for purchase of energy from a RE facility. Any type of 

EGU owner (utility or otherwise) can purchase and retire RECs. 

The fact that RECs are purchased by a diverse set of market 

participants — including residential consumers, commercial 

businesses, and industrial facilities — demonstrates that such a 

purchase for all EGU owners is adequately demonstrated. 

5. Renewable Energy Certificate Markets 

 Affected EGU owners do not need to directly invest in, or 

own, renewable generating capacity in order to replace fossil 

fuel-fired generation with RE as an emission reduction measure. 

Instead, affected EGU owners can pay for any amount of RE 

generation, and claim its environmental attributes, through the 

purchase of renewable electricity certificates (RECs). 

 RECs are used to demonstrate compliance with state RE 

targets, such as state RPS, and also to substantiate claims 

stemming from RE use. RECs are tradable instruments that are 
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associated with the generation of one megawatt-hour (MWh) of RE 

and represent certain information or characteristics of the 

generation, called attributes.615 RECs are traded and transferred 

regardless of the actual energy flow. REC ownership confers the 

right to claim the generation attributes. 

 The legal basis for RECs is established by state statutes 

and administrative rules. Nearly all states with a mandatory RPS 

have established RECs as a means of compliance. The Federal 

Energy Regulatory Commission (FERC) has observed that states 

created RECs to facilitate programs designed to promote 

increased use of RE, and that “attributes associated with the 

[RE] facilities are separate from, and may be sold separately 

from, the capacity and energy.”616 

 In complying with states’ RPS requirements in 2012, 61 

percent of RECs were sourced from in-state resources (65 percent 

 

615 EPA Green Power Partnership, Renewable Energy Certificates 

July 2008). Available at 

http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf. 

616 FERC Docket No. EL03-133-000, Petition for Declaratory Order 

and Request for Expedited Consideration, American Ref-Fuel 

Company, Covanta Energy Group, Montenay Power Corporation, and 

Wheelabrator Technologies, Inc. June 16, 2003, Order Granting 

Petition for Declaratory Ruling, October 1, 2003. American RefFuel Co. et al., 105 FERC ¶ 61,004 (2003); and Order Denying 

Rehearing. April 15, 2004. 107 FERC¶ 61,016 (2004). Available 

online at: http://www.ferc.gov/whats-new/comm-meet/041404/E28.pdf (accessed 11/7/2014). 
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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.617

6. Quantification of Renewable Energy Generation Potential for 

BSER and Major Comments 

The methodology for quantifying RE generation levels under 

building block 3 is a modified version of the alternative RE 

approach from proposal, with adjustments that reflect the data 

and information the EPA collected through stakeholder comments 

and the EPA’s additional analysis and information collection. In 

evaluating the proposed and alternative RE approaches, 

commenters observed that RPS, as the basis for quantifying RE 

generation levels under the proposed approach, are policy 

instruments that states may choose to implement for a variety of 

reasons not related to CO2 emission reductions. Additionally, 

differences across RPS policies in eligible resources, crediting 

mechanisms, deliverability requirements, alternative compliance 

 

617 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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payments, and other policy elements made the regional averaging 

of state-level RPS requirements challenging. Finally, commenters 

provided data demonstrating that RE resource potential can vary 

significantly within the regions identified under the proposed 

approach, producing state-level RE generation levels that may 

not be aligned with the opportunity to deploy incremental RE 

resources at reasonable cost. In contrast, commenters argued 

that a methodology similar to the alternative RE approach, which 

is based on economic potential, represents a more technically 

sound basis for quantifying building block 3 target generation 

levels that accounts for regional differences in RE resources 

and power market conditions, such as projected fuel prices, load 

growth and wholesale power prices. The EPA agrees with these 

comments. 

 Within the framework of the alternative RE approach, the 

EPA received significant comments on a number of issues, 

including the use of historical deployment rates, the interstate 

nature of RE and the power system, use of total RE generation to 

quantify building block 3 generation levels, RE technologies 

that contribute to those generation levels, cost and performance 

estimates associated with those technologies, magnitude of the 

reduced cost applied to new RE capacity as an incentive to 
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deploy, and application of a nationally uniform technical 

potential limiter to modeled projections of economic deployment. 

Based on commenter data and information, as well as further 

analysis and information collection, the primary adjustments the 

EPA made to the alternative RE approach are: 

 The basis for quantifying building block 3 generation has been 

modified to incorporate historical deployment patterns for RE 

technologies as well as the economic potential identified 

through modeling projections. The introduction of historical 

capacity additions to the final methodology further grounds 

building block 3 generation in demonstrated levels of RE 

deployment that have been successfully incorporated into the 

power system. This adjustment also serves to harmonize the 

approach across all three building blocks in which historical 

data is the primary basis for identifying emission reduction 

opportunities under the BSER. 

 The RE technologies used to quantify building block 3 

generation levels are onshore wind, utility-scale solar 

PV, concentrating solar power (CSP), geothermal and 

hydropower. Each of these technologies is a utilityscale, zero-emitting resource that was included under the 

Alternative RE approach at proposal. Additionally, the 
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EPA received significant comments on the opportunities 

and challenges associated with distributed RE 

technologies. Distributed technologies, as a demand-side 

resource, present unique data and technical challenges 

(such as the role of EM&V in verifying their production, 

the diverse economic incentives of different parties 

involved in their deployment, and the variety of grid 

integration policies and conditions across potential 

deployment sites) that complicate identifying a 

technically feasible and cost-effective level of 

generation. Consequently, the EPA is, at this time, 

choosing not to include distributed technologies as part 

of the BSER (although, as explained in section VIII of 

this preamble, distributed RE may be used for 

compliance). Finally, any RE technology that has not been 

deployed in the United States, including demonstrated RE 

technologies for which there is clear evidence of 

technical feasibility and cost-effectiveness (e.g., 

offshore wind), contributes no generation to building 

block 3 under this historically-based methodology. These 

RE technologies are consequently reserved for compliance, 

which offers affected EGUs additional flexibility and 
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will reduce their need to rely on other emission 

reduction measures or building blocks. 

 Building block 3 generation levels are expressed in terms 

of incremental, rather than total, RE generation. As a 

metric, incremental generation is better aligned with 

quantifying an amount of expanded RE to replace 

generation at affected EGUs.618 Specifically, the 

generation levels under building block 3 include 

generation potential of the RE technologies considered 

from capacity that commenced operation subsequent to 2012 

(the data year on which the BSER is evaluated). It is 

unnecessary to include generation from RE capacity that 

was already in operation by 2012 in building block 3 

because its impacts on fossil fuel-fired EGUs are already 

reflected in the observed 2012 emissions and generation 

data of those EGUs. 

 Due to the interstate nature of RE and the power system, 

and consistent with the rationale provided in the October 

 

618 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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2014 Notice of Data Availability (NODA), building block 3 

generation levels are quantified for each of the three 

BSER regions – the Eastern Interconnection, Western 

Interconnection, and Texas Interconnection – rather than 

at the state level. This regionalized approach, as 

described in the NODA, takes into account the opportunity 

to develop regional RE resources and thus better aligns 

building block 3 generation levels with the rule’s 

approach to allowing the use of qualifying out-of-state 

renewable generation for compliance. 

 Commenters observed that the cost and performance 

estimates the EPA relied on at proposal from the Energy 

Information Administration’s Annual Energy Outlook 2013 

do not reflect the decline in cost and increase in 

performance that have been demonstrated by current 

projects, particularly in regards to wind and solar. 

Commenters provided data from a 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 

reevaluated. The EPA revised its data for onshore wind 
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and solar technologies to reflect the mid-case estimates 

from the National Renewable Energy Laboratory’s (NREL’s) 

2015 Annual Technology Baseline. The EPA selected the 

NREL 2015 Annual Technology Baseline (ATB) estimates 

based on the quality of its data and consistency with 

recent RE cost and performance trends. In addition to 

wind and solar technologies, the EPA considered 

hydropower deployment potential based on the latest cost 

and performance data from DOE’s Hydropower Vision 

study.619

 The technical potential limiter that constrained costeffective RE deployment under the alternative approach in 

the proposal has been removed from the final 

methodology.620 Commenters observed several issues with 

applying the technical potential limiter, including that 

this feature limits future performance to historical 

levels of development, does not factor in the total size 

 

619 For additional information on the updated RE cost and 

performance assumptions used to quantify building block 3 

generation, refer to the GHG Mitigation Measures TSD. 

620 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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of the RE resource in a given state, relies on nonexclusive 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 3. 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 contains seven steps. Each step is described 

in detail below. 

First, the EPA collected data for each technology (onshore 

wind, utility-scale solar PV, CSP, geothermal and hydropower) to 

determine the annual change in capacity over the most recent 

five-year period. From this data, the EPA calculated the fiveyear annual average deployment for each technology as well as 
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identifying the maximum annual change in capacity for each 

technology. 

Second, the EPA determined an appropriate capacity factor 

to apply to each RE technology that would be representative of 

expected future performance from 2022 through 2030. For this 

purpose the EPA relied on NREL’s ATB. 

Third, the EPA calculated two generation levels for each 

technology. The first generation level is the product of each 

technology’s five-year average capacity change and the assumed 

future capacity factor. The second generation level is the 

product of each technology’s maximum annual capacity deployment 

over the past five years and the assumed future capacity factor. 

Table 8 below shows the data and assumptions used for these 

calculations. 

TABLE 8. Historical Capacity Changes and Associated Generation 

Levels. 

 Assumed 

Future 

Capacity 

Factor 

Five-Year 

Average 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Five 

Year-Average 

Capacity 

Change (MWh)

Maximum 

Annual 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Maximum 

Annual 

Capacity 

Change (MWh) 

UtilityScale Solar 

PV 

21% 1,927 3,544,909 3,934 7,236,986 

CSP 45% 251 989,442 767 3,023,514 

Onshore 

Wind 42% 6,200 22,811,040 13,131 48,311,575 

Geothermal 85% 141 1,049,886 407 3,030,522 

Formatted Table
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Hydropower 64% 163 913,843 294 1,648,282 

Total N/A 8,682 29,309,120 18,533 63,250,879 

Fourth, the EPA quantified the RE generation from capacity 

commencing operation after 2012 that can be expected by 2021 

(the year before this rule’s first compliance period) with or 

without the imposition of this rule. Because building block 3 

is focused on the ability of fossil fuel-fired EGUs to reduce 

their emissions by deploying additional RE, it is reasonable to 

take into account the considerable amount of RE deployment that 

is already taking place and is commonly projected to continue 

doing so before we consider the additional deployment that would 

be motivated by this rule’s mandate to reduce emissions. The 

EPA considered its base case power sector modeling projections 

using IPM to quantify this component of future-year RE 

generation, which the EPA assumes to be 212,221,098 megawatthours in 2021. 

 Fifth, the EPA applied the generation associated with the 

five-year average capacity change to the first two years of the 

interim period. Combining the 2021 RE generation from 

capacity starting operation after 2012 that was estimated above 

with the generation increment associated with the five-year 
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average change in capacity produces 241,530,219 megawatt-hours 

in 2022 and 270,839,339 megawatt-hours in 2023. The EPA believes 

it is appropriate to apply the generation associated with the 

five-year average capacity change for the first two years of the 

interim period to ensure adequate opportunity to plan for and 

implement any necessary RE integration strategies and 

investments in advance of higher RE deployment levels assumed 

for later years. 

Sixth, for all years subsequent to 2023 the EPA applied the 

generation associated with the maximum annual capacity change 

from the historical data analysis. In 2024, this produces a 

building block 3 generation level of 334,090,218 megawatt-hours 

(aggregated across all three BSER regions); by 2030, that 

generation level is 713,595,494 megawatt-hours. 

Seventh, to further evaluate the technical feasibility and 

cost-effectiveness of the building block 3 generation levels 

(aggregated across all three BSER regions), the EPA conducted 

analysis using IPM of a scenario directing the power sector to 

achieve those RE generation levels. IPM modeling projections 

assess opportunities for RE deployment in an integrated 

framework across power, fuel, and emission markets. The modeling 

framework incorporates a host of constraints on the deployment 
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of RE resources, including resource constraints such as resource 

quality, land use exclusions, terrain variability, distance to 

existing transmission, and population density; system 

constraints such as interregional transmission limits, partial 

reserve margin credit for intermittent RE installations, minimum 

turndown constraints for fossil fuel-fired EGUs, and short-term 

capital cost adders to reflect the potential added cost due to 

competition for scarce labor and materials; and technology 

constraints such as construction lead times and hourly 

generation profiles for non-dispatchable resources by season.621

Additionally, the EPA assumes in this analysis that deployment 

of variable, non-dispatchable RE resources is limited to 20 

percent of net energy for load by technology type and 30 percent 

of net energy for load in total at each of IPM’s 64 U.S. subregions.622 The 30 percent constraint reflects levels commonly 

modeled in grid integration studies at the level of the 

interconnection. These studies have demonstrated that impacts to 

the grid in reaching levels as high as 30 percent of net energy 

 

621 Refer to GHG Abatement Measures TSD for more detail on 

modeling methodology. 

622 Regions that have already exceeded these limits are held at 

historical percent of net energy for load. 
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for load are relatively minor.623 For example, the Western Wind 

and Solar Study Phase 2 found cycling costs ranged from $0.14 to 

$0.67 per megawatt-hour of added wind and solar generation. 

These integration cost levels are not impactful in determining 

cost-effectiveness. As such, applying these constraints at the 

IPM sub-region level does not represent a technical feasibility 

limit but rather a conservative view of deployment levels that 

would not require significant grid integration costs.624 

In addition to facilitating the EPA’s assessment of the 

feasibility and cost of reaching the aggregate building block 3 

generation levels across all three BSER regions, the IPM 

projections also provide the EPA with a basis for apportioning 

those generation levels to each interconnection. The EPA 

considered the projected regional location of the evaluated RE 

deployment in this analysis, which shows the majority of such 

deployment occurring in the Eastern Interconnection. The GHG 

Abatement Measures TSD describes in greater detail the process 

 

623 Wind Technologies Market Report 2013. LBNL. Cochran, et al. 

2014; Grid Integration and the Carrying Capacity of the U.S. 

Grid to Incorporate Variable Renewable Energy. NREL. Cochran, et 

al. 2015; The Western Wind and Solar Integration Study Phase 2. 

NREL. Lew, et al. 2013. Refer to GHG Mitigation Measures TSD for 

further analysis. 

624 Refer to the GHG Abatement Measures TSD for additional 

information on constraints related to deployment of nondispatchable RE. 

Commented [A16]: For the non-technical readers, it might be 

helpful to explain why this is true and not in conflict with the 

statement below that the IPM runs are a feasibility analysis 
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by which the EPA calculated the apportionment of building block 

3 generation levels to each BSER region, taking these modeling 

projections into account. Table 9 describes the annual building 

block 3 generation levels for each interconnection from 2022 

through 2030. 

TABLE 9. Building Block 3 Generation Levels (MWh). 

Year Eastern 

Interconnection 

Western 

Interconnection 

Texas 

Interconnection 

2022 167,140,348 60,154,660 14,235,211 

2023 184,170,751 67,709,835 18,958,754 

2024 220,045,394 83,522,555 30,522,270 

2025 255,920,036 99,335,274 42,085,787 

2026 291,794,679 115,147,994 53,649,303 

2027 327,669,322 130,960,714 65,212,820 

2028 363,543,965 146,773,434 76,776,336 

2029 399,418,608 162,586,154 88,339,853 

2030 435,293,251 178,398,873 99,903,369 

7. Feasibility of Renewable Energy Deployment 

 The 2030 level of RE deployment and the rate of progress 

during the interim period in getting to that level are well 

supported by comments received, DOE analysis, and external 

studies evaluating the costs of and potential for RE 

penetration. The EPA has assessed the feasibility of RE in terms 

of deployment potential, system integration, reliability, backup 

capacity, transmission investments, and RE supply chains. 

Formatted Table
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Historical RE deployment rates are a strong indication of 

the feasibility of the 2030 level of deployment and interim 

period pathway. The use of RE continues to grow rapidly in the 

U.S. In 2013, electricity generated from RE, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity, up from 9 percent in 2005. In particular, there 

has been substantial growth in the wind and photovoltaic (PV) 

markets in the past decade. Since 2009, wind energy has tripled 

and solar has grown ten-fold. 

The expected future capacity installations in 2021-2030 

needed to reach the 2030 level of deployment are consistent with 

historical values. Forecasts by CERA of 17GW in 2015 and 

historical deployment of 16 GW in 2012 are significant. The 

average deployment of wind over the past five years was 6,200 

MW/yr; 2014 deployment of solar PV was 6,201 MW. This 

contribution from solar PV is consistent with the rapid 

reduction in costs that is currently being observed and expected 

to continue. 

Grid operators are reliably integrating large amounts of 

RE, including variable RE today. Iowa and South Dakota produced 

more than 25 percent of their electricity from wind in 2013, 

with a total of nine states above 12 percent and 17 states at 
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more than 5 percent. California served nearly 19 percent of 

total load in 2013 with RE resources, not including behind the 

meter distributed solar resources, and approximately 25% of 

total load with RE in 2014. On an instantaneous basis, 

California is regularly serving above 25% of load with RE 

resources, recently began seeing over 5,000 MWh of solar energy 

and is on track for 33% no serious reliability or grid 

integration issues. Germany was above 28% non-hydro RE as a 

percentage of total energy in first half of 2014. Other recent 

examples include: ERCOT met 40 percent of demand on 3/31/14 with 

wind power; SPP met 33 percent of demand on 4/6/13 with wind 

power; and, Xcel Energy Colorado met 60 percent of demand on 

5/2/13 with wind power. These penetration levels have been 

achieved without negative impacts to reliability with measures 

including expanded operational flexibility, and good 

coordination with other regional markets. 

 Operational and technical upgrades to the power system may 

be required to accommodate high levels of variable, nondispatchable RE like wind and solar. However, the overall 

technical potential for RE development significantly exceeds any 

analysis EPA has conducted to quantify potential building block 

three generation levels. 
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RE can contribute to reliable system operation. The 

abundance and diversity of RE resources in the U.S. can support 

multiple combinations of RE in much higher penetrations. When 

California, the Midwest, PJM, New York, and New England 

experienced record winter demand and prices during the polar 

vortex, wind generation was high and as a result, it played a 

key role in maintaining reliability. 

Wind and solar PV are increasingly productive and capable 

of being accurately forecast which improves grid reliability. 

Increasing capacity factors mean less variability and more 

generation. Wind turbine design changes are driving capacity 

factors higher for projects located in given wind resource 

regimes. Average capacity factors have risen from low 30 

percent range to high 30 percent range. One key recent 

advancement is the increasing use of turbines designed for low 

to medium wind speed sites (with higher hub-heights and larger 

rotors, relative to nameplate capacity) at higher wind-speed 

sites with low turbulence. 

New variable RE generators can provide more electrical 

power grid support services beyond just energy. Modern wind 

turbines power electronics allow turbines to provide voltage and 

reactive power control at all times. Wind plants meet a higher 
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standard and far exceed the ability of conventional power plants 

to “ride-through” power system disturbances, which is essential 

for maintaining reliability when large conventional power plants 

break down. Xcel Energy sometimes uses its wind plants’ 

exceedingly fast response to meet its system need for frequency 

response and dispatchable resources. Utility-scale PV can 

incorporate control systems that enable solar PV to contribute 

to grid reliability and stability, such as voltage regulation, 

active power controls, ramp-rate controls, fault ride through, 

and frequency control. Solar generation is capable of providing 

many ancillary services that the grid needs but, like other 

generators, needs the proper market signals to trade energy 

generation for ancillary service provision. 

The transmission network can connect distant high-quality 

RE to load centers and improve reliability by increasing system 

flexibility. Investments in transmission and distribution 

upgrades also enable improvements in system-wide environmental 

performance at lower cost. 

The potential range of new transmission construction is 

within historic investment magnitudes. Under nearly all 

scenarios analyzed for the QER, circuit-miles of transmission 

added through 2030 are roughly equal to those needed under the 
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base case, and while those base case transmission needs are 

significant, they do not appear to exceed historical yearly 

build rates. DOE’s Wind Vision findings projects 11.5 GW/yr of 

wind from 2021-2030. This deployment level would require 890 

circuit miles/year of new transmission; 870 miles/year have been 

added on average between 1991 and 2013. 11.5 GW/yr exceeds 

building block three deployment levels. DOE’s SunShot scenario, 

which increases utility-scale PV to 180 GW by 2030, required 

spending of $60 billion through 2050. On an average annual 

basis, this expenditure is within the historical range of annual 

transmission investments made by IOUs in recent decades. 

Incremental grid infrastructure needs can be minimized by 

repurposing existing transmission resources. Transmission 

formerly used to deliver fossil-fired power to distant loads can 

– and is – being used to deliver renewable energy without new 

infrastructure. First Solar’s Moapa project uses transmission 

built to deliver coal-fired power from Navajo to Los Angeles. NV 

Energy’s retirement of Reid-Gardner will free up additional 

transmission capacity. The Milford wind projects in Utah already 

utilize transmission that was built to deliver coal power to Los 

Angeles. 
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Storage can be helpful but is not essential for the 

feasibility of RE deployment because there are many sources of 

flexibility on the grid. DOE’s Wind Vision and many other 

studies have found an array of integration options (e.g., large 

balancing areas, geographically dispersed RE, weather 

forecasting used in system operations, sub-hourly energy 

markets, access to neighboring markets). Storage is a system 

resource, as its value for renewables is a small share of its 

total value. 

Increasing regional coordination between balancing areas 

will increase operational flexibility. The Energy Imbalance 

Market (EIM) recently implemented by the California ISO and 

Pacificorp is a good example of the increased coordination that 

will be helpful in ensuring that resources across the West are 

being utilized in an efficient way. 

Significant wind and solar supply chains have developed in 

the past decade to serve the growing US RE market. For wind, 

domestic production capability would likely have to increase to 

accommodate projected builds under the CPP in the 2020-2030 time 

period, however, the global supply chain has expanded 

significantly to serve multiple markets and can support the 

domestic supply chain if necessary. At the start of 2014, the Deleted: .
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U.S. domestic supply chain could produce 10,000 blades (6.2 GW) 

and 4300 towers (8 GW) annually. It is not anticipated that 

expanded domestic manufacturing will be constrained by raw 

materials availability or manufacturing capability. For solar, 

the global supply chain has a capacity that has significantly 

expanded over the past few years from 1.4 GW/yr in 2004 to 22.5 

GW/yr in 2011. Current capacity exceeds these levels and is 

expected to grow. For PV systems, raw materials like tellurium 

and indium are at highest risk of supply shortage. 

There are multiple RE technologies not quantified under building 

block three that affected sources may use to demonstrate 

compliance (distributed PV, offshore wind, sustainable biomass, 

etc.). Based on preliminary analysis from DOE, cost-effective 

opportunities for distributed generation alone could satisfy 

one-third to over one-half of the stringency associated with 

building block three.8. Cost of CO2 Emission Reductions from 

Renewable Energy Generation 

The EPA believes that RE generation at the levels 

represented in building block 3 can be achieved at reasonable 

costs. In the EPA’s modeling of the building block 3 level of RE 

deployment, the projected cost of achieving CO2 reductions 

through this expansion of RE generation is $XX per metric ton on 
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average from 2022 through 2030.625 There are a number of reasons 

why the EPA believes that the cost of CO2 emission reductions 

from RE generation will be lower than this analysis suggests. 

First, modeling constraints that restrict non-dispatchable RE to 

a percentage of net energy for load at each of the 64 U.S. IPM 

regions represent uncertainty associated with grid integration 

costs rather than a determination of technical infeasibility. In 

fact, many regions have already demonstrated levels of RE 

penetration that exceed the constraints, and in practice 

intermittency can be managed across larger regions than the 64.

Consequently, the extent to which these regions could, in 

practice, achieve higher levels of RE deployment without facing 

substantial grid integration costs would lead to a lower-cost RE 

outcome than is estimated from this analysis. Second, there are 

a number of RE technologies not included in building block 3 

that may be used in compliance with the rule, including 

distributed generation technologies, offshore wind, CSP, and 

many other technologies that are already in widespread use.626

Third, in the performance rate- and goal-setting approach 

 

625 Refer to the GHG Abatement Measures TSD for further analysis 

and IPM run results. 

626 See Section VIII.G for a description of qualifying RE 

technologies for compliance 

Deleted: .
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described in sections VI and VII, each of the three BSER regions 

is ultimately assigned the highest of the calculated CO2 

emission performance rates for each subcategory. Consequently, 

a significant amount of the emission reduction potential 

quantified for each building block is not ultimately reflected 

in the interim and final CO2 emission performance rates—and 

would be accessible to sources for compliance. For example, the 

EPA has calculated that up to 160,000,000 megawatt-hours of 

building block 3 potential is not captured in the final CO2 

emission performance rates as a consequence of this performance 

rate- and goal-setting methodology.627 Therefore, it is 

reasonable to expect that it would cost somewhat less to achieve 

the component of building block 3 potential that is reflected in 

the calculation of the final CO2 emission performance rates, as 

compared to the results of this analysis which assumed 

achievement of the entire quantified building block 3 potential. 

The EPA believes that these factors provide significant 

opportunities for achievement of the building block 3 generation 

levels at lower costs than estimated in this analysis. 

VI. Source Category-Specific CO2 Emission Performance Rates 

 

627 For additional discussion on how this concept impacts 

building block 3 generation levels, refer to the GHG Mitigation 

Measures TSD and the CO2 Emission Performance Rate and Goal 

Computation TSD for Final CPP. 

Deleted: some

Deleted: .
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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).628 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 guidelines 

that were based on the aggregation of units, and their reduction 

potential, in a state rather than providing technology-specific 

guidelines. While many commenters appreciated the flexibility 

this state-focused structure provided, some noted two concerns 

 

628 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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with this approach: 1) it would potentially create different 

incentives for the same generating technology class depending on 

the state in which that generator was located, and 2) it 

deviated from the EPA’s previous interpretation of the 111(d) 

regulatory guidelines by not providing technology-specific 

standards of performance. In response to comments, the final 

rule establishes subcategory-specific emission performance rates 

that are identical across units within a subcategory regardless 

of where a unit is located within the contiguous U.S. 

These 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 

technology categories as they scale up to their full BSER 

potential by 2030. The performance rates are meant to reflect 
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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 

adjusted629 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 would not be expected to produce the level of 

emission reduction quantified by the EPA because implementation 

 

629 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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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 Mitigation 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 contiguous U.S., and a 

single rate for existing gas turbines in the contiguous U.S., 

reflecting application of the BSER, based on all three building 

blocks described earlier, to pertinent data. The rates are 
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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 

1,548 1,305 

Stationary Combustion 

Turbines 

850 771 

 

 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 

Formatted Table
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associated with an achievable amount of qualifying incremental 

lower-carbon and zero-carbon generation and substituting those 

MWhs (along with corresponding emissions) for the baseline 

electricity generation and CO2 emissions from the higher-emitting 

affected EGUs. Under the final rule approach, regionally 

identified building block three potential generation replaces 

fossil steam and NGCC generation on a pro-rata basis 

corresponding to the historical baseline mix of fossil 

generation in each region. However, as discussed in Section 

VIII, if the state decides to implement these adjustments in its 

state plan, the state must still demonstrate compliance with the 

CO2 emission performance rates for affected EGUs or the 

equivalent state-based goals provided in section 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 
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rates in a manner similar to proposal, with an adaptation to 

address the revised timing of the interim compliance period 

(beginning in 2022 rather than in 2020 as proposed). They 

reflect the averaging of estimated emission performance rates 

for each year in the interim period (i.e., 2022-2029). 

The interim performance rates are less stringent than the 

final 2030 emission performance rates because the amount of 

emission reduction potential identified for the BSER increases 

over time, as explained in section V above. 

C. Form of the Performance Rates 

1. Rate-based guidelines 

 The interim and final emission performance rates for fossil 

steam and NGCC units are presented in the form of adjusted 

output-weighted-average CO2 emission rates that the affected 

fossil fuel-fired units could achieve, 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
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emissions by reducing the quantity of fossil fuel-fired 

generation and associated emissions; and the adjustability of 

the goals based on the severability of the underlying building 

blocks. 

a. Rationale for rate-based guidelines. First, the EPA sets an 

emission rate requirement for each 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 affected fleet level for a 

state. 

Stakeholders have expressed support for having the 

flexibility to choose from among the multiple options for 

crafting an implementation plan to realize the BSER. The EPA is 

providing emission performance rate-based guidelines that apply 

uniformly to technology categories nationwide, and the EPA is 
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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. 

b. Net vs. gross MWh. The second aspect noted above concerns 

the expression of the goals in terms of net energy output630 – 

that is, energy output encompassing net MWh of generation 

measured at the point of delivery to the transmission grid 

rather than gross MWh of generation measured at the EGU’s 

generator. The difference between net and gross generation is 

the electricity used at a plant to operate auxiliary equipment 

such as fans, pumps, motors, and pollution control devices. 

Because improvements in the efficiency of these devices 

represent opportunities to reduce carbon intensity at existing 

affected EGUs that would not be captured in measurements of 

emissions per gross MWh, goals are expressed in terms of net 

generation. As noted by commenters, EGUs have familiarity and in 

 

630 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. 
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some places already have in place the equipment necessary to 

collect and report hourly net generation.631

c. Output-weighted performance rates for all affected EGUs. 

This final rule provides an expression of the BSER that stops 

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.632 These 

two emission performance rates are the expression of the BSER 

for the final rule for affected EGUs located within the 

contiguous U.S. 

 

631 Specifically, commenters noted that while net generation is 

not reported to the EPA under 40 CFR Part 75, affected EGUs are 

generally required to report gross and net generation on a 

monthly basis to EIA through form 923 submittal.

632 However, as discussed here and in the next section, in order 

to provide maximum flexibility to states, the EPA averages these 

two emission rates together for each state using their adjusted 

2012 baseline generation share to arrive at a single statewide 

emission performance goal. The state has the option to comply 

with this statewide goal through a compliance pathway of its 

choice. This compliance pathway may or may not involve requiring 

its affected units to meet the emission performance rates. 
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The modification from a blended emission rate in the 

proposed rule to a subcategory-specific emission performance 

rate for affected EGU categories in the final rule was made in 

response to comments that technology subcategory-specific 

emission rates were more analogous to prior 111(d) efforts and 

more consistent with the statute. The EPA received significant 

comment suggesting a technology subcategory-specific is 

consistent with past section 111(d) regulations. However, many 

commenters also supported the flexibility provided to states 

through a state goal metric provided at proposal. Therefore, the 

EPA does provide alternative statewide rate-based and mass-based 

compliance goals in the next section. 

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 
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demand, opportunities exist to manage utilization of high 

carbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this 

means that CO2 emission reductions can be achieved by shifting 

generation from EGUs with higher CO2 emission rates, such as 

coal-fired EGUs, to EGUs with lower CO2 emission rates, such as 

NGCC units. Our analysis indicates that shifting generation 

among EGUs offers opportunities to achieve large amounts of CO2

emission reductions at reasonable costs. The realization of 

these opportunities can be reflected in an emission rate 

established in the form of an output-weighted-average emission 

rate where the weighting reflects the varying levels of 

replacement generation technologies. 

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 
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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 

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 Mitigation Measures TSD. 

1. Inventory of likely affected EGUs 

In order to calculate the subcategory-specific 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 
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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 

a unit’s status was unclear, the EPA generally treated the 

unit’s status in a manner consistent with the proposal.633

Since the final rule’s applicability includes under 

construction units, the EPA also identified units that had not 

yet commenced operation by the 2012 baseline period, but that 

commenced construction before January 8, 2014. The EPA received 

significant comment on the proposal’s sole use of the National 

 

633 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 

collective changes to the affected fleet inventory will not 

yield a bias in the BSER computation at the regional level. 
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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 

well as NEEDS data to identify these “under construction” 

units.634,635 

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.636 

 

634 The NEEDS database was also updated to reflect the latest 

data and commenter input on under construction units. 

635 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. 

636 The baseline inventory relies on historical data and does not 

incorporate anticipated future retirements. Most commenters 

supported this treatment as they viewed those scheduled 

retirements (and corresponding emission reductions) as an 
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The EPA received significant comment that units that came 

online during the baseline year (e.g., 2012) should be treated 

as under construction rather than operating units in 2012 for 

purposes of estimating baseline values, because their 2012 

operation may be misrepresentative of anticipated future-year 

operation due to partial year operation in 2012. The EPA has 

made an adjustment to flag these units as having commenced 

operation during 2012 and treat them as under construction 

units, consistent with commenters’ suggestion; for BSER 

computational purposes, generation and emissions for these units 

are estimated based on a 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 or a projected-year data set as a 

starting point for applying the technology assumptions 

identified under BSER. The EPA proposed using 2012 data as it 

was the most recent data year for which complete data were 

available when the EPA undertook analysis for the proposed rule 

and it reflected actual performance at the state level. The EPA 

 

alternative compliance flexibility based on already scheduled 

reductions. 
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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. 

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 to 

its baseline year where it still largely relies on reported 2012 

data as the best and most recent available data representing the 

power sector from which to apply the BSER, but also including 

targeted baseline adjustments to address commenter concerns with 
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2012 data.637 Below, we explain why – at the nationwide level - 

2012 data are preferable, more objective, and more accurate than 

a prior year, or an average of years, for informing the 

baseline. Then, we explain the adjustments that we are making to 

the 2012 data along with our rationale for such adjustments, in 

response to comments we received. 

Some commenters supported the EPA’s use of 2012 data to 

inform performance rates, and the EPA agrees that 2012 data with 

targeted adjustments, relative to other historical years, best 

reflects the power sector and best informs the performance rates 

that pertain to the BSER. The EPA believes that starting with 

2012 data is more accurate and better informs the BSER than an 

earlier historical year or historical multi-year average for the 

following reasons: 

1) Of the historical data fully available at the time the 

proposal analysis began, 2012 was the most recent and 

best reflects the power fleet. Approximately 43 GW of new 

capacity came online in 2010 and 2011. In other words, 

there was 43 GW of capacity online as of 2012 that had 

 

637 The EPA recognizes that more recent emissions and generation 

data have become available since 2012, but 2012 data constituted 

the most recent year for which full data was available at the 

time the EPA began its analysis for proposal. 
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not been in service at some point during the 2010-2011 

period. Likewise, approximately 17 GW of capacity that 

operable in 2010 and/or 2011 were retired prior to 

2012.638 Using state-level, prior year data, either on its 

own, or as part of a multi-year baseline, is not as 

representative of the current power fleet as the 2012 

data, which better reflects significant changes in power 

sector infrastructure. 

2) A three-year baseline would not address some of the 

substantive concerns raised by commenters. Many 

commenters pointed out that using a three-year baseline 

would not address their critical concern about variation 

in the hydrological cycle due to snow pack (particularly 

in the Northwest), because the snow pack was 

significantly above average in both 2011 and 2012. The 

EPA agrees with commenters that we can better address 

their baseline data concerns regarding an average hydro 

year by identifying those states with a significant share 

of hydro generation and variation in that hydro 

generation, and making targeted adjustments to those 

states’ affected fossil generation levels in order to 

 

638 EIA Form 860, 2012.
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reflect a more typical snow-pack year. This procedure is 

described in more detail below and in the Technical 

Support Documents. 

3) In addition to being, in the EPA’s view, a less 

representative baseline of the existing power fleet, a 

multi-year baseline would also likely entail complexity 

when determining how to average together yearly fleet 

data while appropriately accounting for fleet changes 

occurring during those years. The 2012 baseline starting 

point maximizes the EPA’s reliance on latest reported 

operating data and minimizes the need for fleet capacity 

adjustments. For instance, because of year-to-year fleet 

turnover, the averaging of a multiple baseline years 

would require additional assumptions in regards to which 

generation to consider from a fleet that is changing in a 

given state or region (or even where units are switching 

fuel sources such as a coal-to-gas conversion). 

4) Due to the region-based nature of 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 
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fossil unit in the same region is generally operating 

more. Therefore, at the regional level, fossil generation 

and emissions do not vary to the same degree that unitlevel data varies. Moreover, the variation at the 

regional-level that does exist in 2012 relative to 

previous years is not necessarily unrepresentative 

variation, but illustrates trends in the power sector 

infrastructure that are desirable to capture for purposes 

of determining a representative year from which further 

improvements in CO2 emissions performance can be made. 

Because the EPA is moving from a state approach at 

proposal to a regional approach for calculating the 

expression of the BSER in this final rule, unit-level 

operational variation from year to year becomes even less 

relevant to the calculation of regional emission 

performance rates (i.e., an outage in a fossil unit in 

one region is likely to be offset by increased generation 

from another fossil unit in that same region). 

5) Some commenters suggested the EPA use an earlier baseline 

year as a means of recognizing early action. They noted 

that an earlier baseline would reflect a higher-emitting 

fleet and therefore when the same level of building block 
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MWhs are applied, they would result in a higher (i.e., 

less stringent) state goal. The EPA disagrees with this 

view for several reasons. First, the objective of 

selecting a baseline to inform BSER is to have one that 

best reflects the power sector and consequently the best 

system of emission reductions of which the power fleet is 

capable. Using an earlier baseline that “inflates” the 

starting point would undermine this objective, not serve 

it. Second, the EPA disagrees with the premise of this 

comment – that the baseline would change and building 

block potentials would stay the same. For instance, 

building block two is based on incremental generation 

potential (incremental generation = potential generation 

– existing generation). This incremental value would 

increase if an earlier baseline period was used that had 

less existing NGCC generation. 

6) Some commenters pointed out that the EPA relied on multiyear historical data in allowance allocation in previous 

rulemakings (e.g., CAIR and/or CSAPR allocations). 

However, that comparison is not relevant to the 

quantification of emission reduction potential under 

111(d). In those previous instances, the EPA was 
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considering typical unit-level behavior for allowance 

allocation purposes – not for determining the emission 

reduction requirements of the program. Those allowance 

allocation determinations were independent of and 

subsequent to the determination of emission reduction 

requirements in those rulemakings. 

7) The EPA received significant comment that 2012 was not a 

representative year for natural gas prices, and thus the 

EPA should use another year. The EPA disagrees with this 

comment, and does not view it as grounds for a change to 

the baseline period. While the EPA does recognize that 

Henry Hub natural gas prices 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 

generation in 2012 when gas prices dropped. However, this 

does not change the outcome of the EPA quantification of 
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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 

The EPA made corrections to unit-level 2012 data based on 

commenter feedback. In addition, we also made some adjustments 

to 2012 data, not to address a correction, but to address a 

concern about the representativeness of the data. Although the 

EPA determined that the 2012 data year better informed its BSER 

determination than a preceding year or a multi-year average, 
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commenters did identify some limitations that we are addressing 

through targeted adjustments. These are discussed below: 

1) Adjustments to state-level data to account for annual 

variation in the hydrologic cycle as it relates to fossil 

generation. 

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.639 Therefore, no similar adjustment was needed to 

account for weather patterns with these technologies. 

Unlike market conditions (e.g., changes in natural gas 

prices) that may produce different generation profiles 

year-to-year but that do not change the overall generating 

potential of the state’s power fleet, variation in the 

hydrologic cycle does fundamentally change the generating 

 

639 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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potential of the state’s power fleet in hydro-intensive 

states as they no longer have the same generating potential 

in an average year as they had in a “high hydro” year. The 

CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule provides analysis and explains the 

adjustment that the EPA made to the state-level 2012 data 

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 

subcategory-specific performance rates reflecting BSER. For 

instance, as some units ramp down, and others ramp up to 

replace their load at the regional level, total fossil 

generation changes little due to these fossil-for-fossil 

substitutions. Unit-level variation does not inherently 

entail region-wide variation. 
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However, the EPA did receive comment that in limited cases, 

this could have a substantial impact on an individual state 

if it chooses to use a rate-based or mass-based statewide 

goal. Even though the EPA is calculating subcategoryspecific performance rates that it believes are not 

affected by this type of unit-level variation, it still 

evaluated the possible impacts it may have when 

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) decreased its output relative to preceding and 

subsequent years by 75 percent (signifying an outage), and 

2) could potentially impact the state’s goal as it 

constituted more than 10 percent of the state’s generation 

was the 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 
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baseline data) to reflect a more representative year for 

the state in which this 900 MW unit operates. 

3) Many commenters also noted that because the EPA uses annual 

data, 2012 was not representative for units coming online 

part way through the year. The EPA relies on annual data, 

so if a unit is underrepresented in a certain part of the 

year because it is not yet online, then another unit is 

likely over-represented as it is operating more than it 

otherwise would when the second unit commences operation. 

Therefore, the resulting state-level and regional-level 

aggregate annual generation level used in determining the 

BSER may be considered to be representative and there is 

not necessarily a need for any adjustment. 

However, the EPA recognizes that the over-represented and 

under-represented units do not necessarily fall within the 

same state, and therefore this potential difference in the 

state location of the affected units could have an impact 

when estimating appropriate statewide goals. To address 

this comment, the EPA adjusted the 2012 generation data for 

fossil units coming online during 2012 to represent an 

average annual operating level for that type of unit, which 

resulted in increased baseline emissions and generation 
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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 

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, in addition to 

corrections identified by commenters, to the 2012 data to 

address some of the relevant concerns raised by commenters.640

4. Equation 

This section describes the equation used to determine the 

emission performance rates for fossil steam and NGCC units. More 

 

640 Updated unit-level data reflecting corrections identified by 

commenters to the underlying 2012 file is provided in Appendix 1 

of the CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule. The adjustments made to the aggregate data to 

address representativeness concerns are provided in Appendix 3.
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detailed information regarding rate computation, including 

example calculations, can be found in the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule, 

which is available in the docket for this action. 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 

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 likely affected EGUs that had commenced operation prior to 
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2012.641 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 

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 

 

641 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 (CTs) were excluded on this basis at proposal, and all 

simple cycle CTs were excluded at final reflecting changes to 

the applicability language. IGCC’s were designated as “other” 

generation at proposal, but they are grouped with coal units for 

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 and uncertainty of thermal load outputs. As 

described in the state plan section of the preamble, units may 

still quantify and convert UTO (i.e., taking credit for waste 

heat capture) when demonstrating compliance. See the 

applicability criteria described in Section IV.C above. 
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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 

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 
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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 historical 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 aggregated it to the 

regional level prior to building block application. The regions 

reflect the Eastern, Western, and Texas Interconnections. The 

shift to a regional framework was based on comments suggesting 

that the EPA would better capture the interstate impacts of the 

building blocks under a regional structure. The basis for the 

regions is defined and discussed in Section V.A.3). 

Step three (identification of source category baseline 

emission rates). As discussed in the beginning of this section, 

the EPA took a technology-specific approach to quantifying 

guidelines. Therefore, whereas the proposal first averaged the 
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fossil steam rate and NGCC rate together before applying the 

building blocks and defining state goals, the final rule applied 

the building blocks at the regional level maintaining a separate 

fossil steam rate and a NGCC rate for each region. The starting 

point for calculating the technology-specific emission 

performance rates was 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 fleet in each 

region was reduced by 2.1, 2.3, and 4.3 percent in the Western, 

Texas, and Eastern Interconnections respectively, while the coal 

generation level was held constant, reflecting the EPA’s 

assessment of the average opportunities in each region to reduce 

CO2 emission rates across the existing fleet of coal-fired steam 

EGUs through heat rate improvements that are technically 

achievable at a reasonable cost. The EPA then averaged together 

the region’s baseline oil- and natural gas-fired steam rate with 
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its building block 1 adjusted coal steam rate to get a fossil 

steam rate post building block 1.642,643 

 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 building block two incremental NGCC 

potential were ultimately applied to replace higher-emitting 

 

642 Building block 1 analysis acknowledges some variation in heat 

rate improvement potential at different units. The 

implementation of this building block reflects a heat rate 

improvement on average across a region’s coal fleet, not 

necessarily a heat rate improvement at every unit. 

643 Baseline OG steam emissions are added to adjusted coal 

emissions and divided by baseline OG steam generation and 

baseline coal generation. 
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fossil steam generation and emissions. Commenters noted that 

building block three should be applied first, or the EPA would 

risk understating the potential of building block 2 by not 

realizing the full 75 percent utilization level of NGCC and its 

ability to replace fossil steam. The EPA agrees and calculated 

the building block impacts first in the equation. Incremental RE 

potential is also lower emitting than building block two 

incremental NGCC potential, so calculating building block 

three’s replacement first when determining the impact on 

technology rates for each affected fossil-fuel subcategory is 

consistent with the BSER. 

First, building block three replacement potential was 

identified for each region to arrive at a total amount of 

incremental zero-emitting generation hours available to replace 

fossil generation in the region. Next, the incremental zero 

emitting generation hours were 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.644 The EPA determined the percent of fossil steam 

 

644 The EPA took comment on a pro-rata or an intensity-based 

replacement approach. In this final rule, the EPA agrees with 

commenters that a pro-rata approach is a better reflection of 

BSER. Incremental RE generation has, and is likely to continue, 

Commented [A17]: Does this description match the 

mathematical process that is used to reach the state goals? 
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generation and the percent of NGCC generation of total affected 

fossil generation in each region’s baseline. We then assigned 

those percentages of the incremental zero-emitting MWhs to each 

of those technology source categories.645 The incremental zeroemitting generation assigned to that technology replaced the 

respective fossil generation from that technology’s baseline 

value. The numerator (emissions) was also effectively reduced at 

this stage by the amount of average CO2 emissions associated with 

the replaced fossil generation. 

Step six (application of building block two). If the 

remaining generation level for the NGCC fleet in a region, 

taking into account the previous steps replacement of NGCC 

generation, was less than 75 percent of the fleet’s potential 

summertime generating capacity (75 percent capacity factor), 

then the NGCC generation in the region was assumed to increase 

to levels equal to the lesser of 1) its potential at 75 percent 

 

to replace both steam and gas turbine generation and the BSER 

captures this through a pro-rata distribution of identified 

building block three potential. 

645 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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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 was 

only assumed to reach 75 percent if there was higher-emitting 

fossil steam generation that it could replace after step five. 

The increase in NGCC generation was matched by an equal decrease 

in fossil steam generation. This reduced the amount of fossil 

steam generation in the fossil steam rate denominator as well as 

the amount of fossil steam emissions in the numerator.646

As explained in step seven, when determining the final 

fossil steam rate, a portion of the total NGCC generation and 

corresponding emissions were assigned to the fossil steam rate 

denominator and numerator respectively. That is, a portion of 

the incremental NGCC generation that replaced fossil steam 

generation was included in the fossil steam denominator and the 

corresponding NGCC emissions were included in the numerator.647 

 

646 For purposes of determining the emission performance rates 

for fossil steam, incremental NGCC generation assigned to the 

fossil steam rate is defined as the final adjusted NGCC 

generation level after step six minus the baseline level. The 

EPA has determined that this approach is most compatible with 

measuring and quantifying NGCC emission reduction credits (ERCs) 

as described in section VIII. 

647 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 
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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 quantified 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. 

For the numerator of the fossil steam rate, the EPA 

multiplied the remaining fossil steam generation (post step six) 

by the fossil steam rate reflecting the heat rate improvement 

from building block 1 (step four). We then added in the 

emissions associated with incremental NGCC generation from 

building block 2 (step six) by multiplying the incremental NGCC 

generation (delta between the baseline NGCC generation level and 

 

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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post step six NGCC generation) by the baseline NGCC rate for 

that region.648 This constitutes the numerator of the fossil 

steam emission rate. 

For the fossil steam denominator, the EPA added the 

remaining fossil steam generation (post step six), the 

incremental NGCC generation, 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 

resulted in a regional adjusted fossil steam rate reflecting the 

three building blocks. 

For the NGCC performance rate, the EPA calculated a 

numerator in a similar manner. First, we took the remaining NGCC 

generation (post step six) and multiplied it by the regional 

baseline NGCC rate to calculate the total emissions in the 

numerator. For the denominator, the EPA added the remaining NGCC 

generation (post step six) to the amount of zero-emitting 

building block three generation assigned to that technology in 

 

648 See CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule for an illustration of this step. The EPA defined 

the “incremental NGCC generation” in this step in a manner 

consistent with its measurement described in section VIII of 

this preamble. 
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step five. Dividing the emissions into this total generation 

value (inclusive of the RE generation apportioned to NGCC) 

provided a regional adjusted NGCC rate.649

Step eight (determining the nationwide subcategory-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 repeated steps four through eight for each 

year 2022-2030.650 The resulting annual rates vary because the 

 

649 See CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule for an illustration of this step. We note that 

the entire NGCC generation level (inclusive of the amount 

assigned to the fossil steam rate) expected post building block 

application is included in the NGCC rate calculation. Including 

the entire NGCC generation in the NGCC rate reflects a more 

conservative rate that recognizes the simultaneous compliance 

responsibility of affected NGCC units while the fossil steam 

rate recognizes its mitigation potential through incorporation 

of the incremental NGCC generation component. 

650 At proposal, the EPA repeated this step over a 10 year 

period. The building blocks and corresponding BSER emission 

rates increased for ten consecutive years (2020-2029) in the 

EPA’s rate calculation. In this final rule, the EPA has 

maintained the same 2030 compliance period for final rates but 

adjusted the start date to 2022 based on comments. Therefore, 

the deployment of building blocks is spread over a nine year 

period (2022-2030) instead of the proposed 10 year period. 
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amount of building block two and three potential in each year 

varies. The rates for years 2022-2029 were averaged together to 

calculate an interim rate, and the 2030 value becomes the final 

emission performance rate for that year forward. 

 It bears emphasis that the procedure described above was 

used only to determine emission performance rates, and the 

particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

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 
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cases has already experienced turnover beyond the baseline 

period. However, while the system’s fleet may change, the EPA 

believes this turnover will only further promote the feasibility 

of the emission performance rates. Fleet turnover has trended 

towards, and is expected to continue to trend towards, loweremitting generation sources that will make reductions more 

readily available. 

 

VII. 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 
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and requested a simple and transparent method for determining 

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 
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is complying with the technology-specific emission performance 

rates on average if a state chooses not to apply the performance 

rates to its affected EGUs directly. As discussed further in 

section VIII on state plans, the states, in turn, are charged 

with setting specific emission standards for the EGUs in their 

respective jurisdictions such that the EGUs operating under 

those standards together satisfy the requirements of the final 

emission guidelines as expressed by the emission performance 

rates or statewide emission performance goals. 

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 

subcategory-specific emission performance rates to determine a 

statewide goal. While the emission performance rates reflect the 

quantification of performance based on the BSER, the statewide 

goals reflect one alternative approach through which states may 

choose to adopt and implement those subcategory-specific 

performance rates. 

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 
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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 

emission total is divided into that state’s baseline generation 

values from the likely affected units in order to develop a 

state’s rate-based CO2 emission performance goal for 2030. This 

blended rate reflects the aggregate emission rate a state may 

expect to achieve when its baseline fleet of likely affected 

units continues to operate at baseline levels while 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 
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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 potential gradual 

reduction compliance strategy that states may use to reach their 

interim and final statewide goals.651

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 

 

651 Utilizing the 3-year, 3-year, 2-year performance rates to 

demonstrate compliance with the interim goal is conditional on 

the generation levels observed in those time periods. It is 

possible that a state/source could meet these 3-year, 3-year, 2-

year requirements and be in over/under compliance with the 

interim goal. Ultimately, states/sources need to demonstrate 

compliance with the interim and final goals. 
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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 

tons into each state’s mass-based goal on the basis of that 

state’s share of 2012 affected EGU generation.652 

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 

 

652 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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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 

inventory, the EPA will consider allowing states, via State Plan 

submittal, to adjust their statewide rate or mass goal by up to 

1 percent if such a change is necessary.653 

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 

 

653 This would require demonstration that the actual changes in 

the affected unit inventory for the given compliance year 

results in a tighter statewide rate-based or mass-based goal 

when using the EPA methodology for determining statewide goals.

Commented [A18]: Would it be possible to discuss how the 1% 

potential adjustment would be adequate to address the expected 

inventory adjustments? 
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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. 

 

Rate-based statewide CO2 emission performance goals are 

listed below in Table 9. Mass-based statewide CO2 emission 

performance goals are found in Table 10. 

Table 9. Statewide654 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 1,264 1,154 1,067 1,173 1,018 

Arizona* 1,283 1,169 1,080 1,190 1,030 

 

654 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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Arkansas 1,431 1,294 1,191 1,319 1,130 

California 981 916 855 925 828 

Colorado 1,497 1,349 1,240 1,377 1,174 

Connecticut 918 863 808 870 786 

Delaware 1,112 1,026 953 1,040 916 

Florida 1,116 1,029 956 1,044 919 

Lands of the Fort 

Mojave Tribe 896 844 792 850 771 

Georgia 1,310 1,192 1,101 1,214 1,049 

Idaho 896 844 792 850 771 

Illinois 1,603 1,438 1,319 1,470 1,245 

Indiana 1,598 1,434 1,315 1,466 1,242 

Iowa 1,659 1,485 1,360 1,519 1,283 

Kansas 1,674 1,498 1,372 1,532 1,293 

Kentucky 1,663 1,489 1,364 1,523 1,286 

Louisiana 1,418 1,283 1,181 1,308 1,121 

Maine 907 854 800 861 778 

Maryland 1,664 1,490 1,365 1,524 1,287 

Massachusetts 975 911 851 920 824 

Michigan 1,488 1,342 1,234 1,370 1,168 

Minnesota 1,555 1,398 1,283 1,428 1,213 

Mississippi 1,155 1,062 985 1,078 945 

Missouri 1,642 1,471 1,348 1,504 1,271 

Montana 1,692 1,512 1,385 1,548 1,305 

Lands of the 

Navajo Nation 1,692 1,512 1,385 1,548 1,305 

Nebraska 1,679 1,502 1,376 1,537 1,297 

Nevada 1,020 949 885 960 854 

New Hampshire 1,026 953 889 964 858 

New Jersey 956 895 837 904 811 

New Mexico* 1,455 1,314 1,209 1,341 1,146 

New York 1,114 1,028 955 1,042 917 

North Carolina 1,439 1,300 1,197 1,327 1,135 

North Dakota 1,692 1,512 1,385 1,548 1,305 

Ohio 1,521 1,369 1,258 1,398 1,190 

Oklahoma 1,339 1,216 1,122 1,239 1,068 

Oregon 1,045 970 903 981 871 

Pennsylvania 1,379 1,250 1,152 1,274 1,095 

Rhode Island 896 844 792 850 771 
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South Carolina 1,469 1,326 1,219 1,353 1,155 

South Dakota 1,485 1,339 1,231 1,367 1,166 

Tennessee 1,552 1,395 1,281 1,425 1,211 

Texas 1,299 1,183 1,092 1,204 1,041 

Lands of the Ute 

Tribe of the 

Uintah and Ouray 

Reservation 1,692 1,512 1,385 1,548 1,305 

Utah* 1,504 1,355 1,245 1,383 1,179 

Virginia 1,139 1,049 973 1,064 934 

Washington 1,212 1,110 1,028 1,128 983 

West Virginia 1,692 1,512 1,385 1,548 1,305 

Wisconsin 1,499 1,351 1,242 1,379 1,176 

Wyoming 1,683 1,505 1,378 1,540 1,299 

* 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 

Arizona* 

Arkansas 

California 

Colorado 

Connecticut 

Delaware 

Florida 

Georgia 

Formatted Table
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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 
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Nevada 

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 
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West Virginia 

Wisconsin 

Wyoming 

* Excludes EGUs located in Indian country within the state. 

C. Addressing Leakage as Part of Equivalency of Statewide CO2

Emission Performance Goals 

For both emission performance rates and statewide CO2

emission performance goals, whether in the form of rate or mass, 

the EPA has created a goal-setting methodology that accounts for 

the dynamic nature of the power sector and the electricity grid. 

The EPA has also created a state plan framework that provides 

approaches to implement emission performance rates and goals 

that account for changes to the grid going forward. Goals and 

state plan approaches have also been structured to minimize 

possible economic distortions based upon differing 

characteristics between states. 

In addition, the agency is further accounting for the 

dynamic nature of the grid by addressing the risk of increased 

emissions that can be caused when generation shifts over time 

from affected sources under the rule to unaffected sources (what 

is often termed “leakage”). A key concern under this rule is 

leakage to what Section 111 defines as “new” units. While 
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covered under the 111(b) standards, new sources are a category 

of fossil EGUs that are not covered by this final rule. As is 

explained below, the EPA has found that the risk of generation 

and emissions leakage to new units is greatest under mass-based 

plan approaches. Therefore addressing the risk of leakage is 

necessary to assure equivalency between emission performance 

rates and mass-based statewide CO2 emission performance goals. 

Because of the integrated nature of the power sector, 

shifts in generation across affected sources will likely occur 

as part of the implementation of this rule. However we do not 

consider much of this shifting to be leakage or to be 

contradictory to the intent of the rule. In fact, our definition 

of BSER not only allows for shifts in generation and emissions 

among regulated sources but is premised upon such shifts. 

Movement of generation between sources is needed to produce 

overall reductions, particularly movement from higher-emitting 

affected sources to lower-emitting affected sources, and from 

all affected sources to zero-emitting RE. In all of these cases 

the fossil sources are subject to obligations under this final 

rule. The same is not true for shifts between affected and 

unaffected fossil sources, which can result in increased 

emissions. Increased emissions due to increased utilization of 
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unaffected fossil sources is contradictory to the policy and 

should be minimized, as it does not reflect the “best system of 

emission reduction” as Section 111(a) requires in its definition 

of standards of performance. 

We acknowledge that there are shifts in generation across 

affected sources that could lead to greater or lesser emissions. 

Strategies included in the rule act to prevent perverse 

incentives that could result in greater overall emissions. For 

example, states that are engaging in rate-based trading through 

an emission standards plan approach must implement the same 

rate-based goal or the uniform emission performance rates (see 

Sec. VIII.L). 

Additionally, under a rate-based emission performance rate 

or statewide CO2 emission performance goal formulated as a rate, 

affected sources have key flexibilities inherent in rate-based 

compliance that minimize the risk of leakage. Primary among 

these flexibilities is the opportunity for affected EGUs to 

maintain or increase utilization from historical levels. This is 

discussed above in Sec. VII.B. This capacity for affected EGUs 

to increase utilization allows the units to respond to increases 

in demand, and avoids generation increases at non-affected EGUs 

including new units. Specifically, under a rate-based approach, 

Deleted: .

Commented [A19]: As meeting new demand is not included in 

the analysis of the BB2 potential, is this the correct way to frame this 

dynamic? Perhaps it would be better to differentiate the incentive to 

meet existing demand with new versus existing sources in a rate 

versus a mass based context? 
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the emission performance rate encourages lower emissions from 

existing lower-emitting affected sources, primarily NGCC, to 

maximize their utilization above historical levels. New units 

that are not affected by the rate will not experience the same 

incentive. 

However, this opportunity to increase utilization is not 

available in mass-based compliance options. In a mass-based 

context, existing lower-emitting units are instead encouraged to 

reduce utilization while new units are not limited in the same 

way. Thus there is a risk of leakage in the mass-based context 

that is not present to the same degree in rate-based 

implementation. 

This rule specifies how implementation of mass-based CO2

emission performance goals are equivalent to emission 

performance rates. In order to assure this equivalency, the 

higher risk of leakage under a mass-based approach must be 

addressed. Therefore, the EPA is requiring that states adopting 

a plan based upon a mass-based statewide CO2 emission performance 

goal demonstrate that they have addressed the risk of leakage in 

their mass-based state plan and show that there is equivalency 

with a rate-based approach. The required demonstration is 

discussed in detail in section VIII.L on Interstate Effects. 

Commented [A20]: This sentence does not make sense as 

written—perhaps it could be reworded? As generation and 

emissions from NGCC are expected to increase under BSER, how 

does the emission rate encourage lower emissions? 
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VIII. State Plans 

[Note to readers – the text that was in section VIII.G in the 

previous version has been moved and renumbered to become 

sections VIII.I-L] 

A. Overview 

After the EPA establishes the emission guidelines, each 

state655 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. The EPA has developed a BSER and a 

mechanism (e.g. standard of performance (e.g. subcategory 

specific emission performance rates)) that allows affected EGUs 

in all states to access all the components of the BSER (as well 

as other alternative but acceptable emission reduction 

opportunities). That standard of performance may expressly 

incorporate the CO2 emission performance rates the EPA has set 

forth in these guidelines to express the BSER. The EPA has also 

received numerous comments from a wide range of stakeholders 

desiring freedom to consider a wide range of standards of 

performance to implement BSER. Thus, as an alternative to 

 

655 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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incorporating the CO2 emission performance rates, 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 subcategory specific CO2 emission 

performance rates, as well as state-specific rate-based and 

mass-based CO2 emission goals for affected EGUs that represent 

the equivalent in aggregate of the CO2 emission performance rates 

applied to the affected EGUs in each state. As already stated, 

the EPA is establishing rate-based CO2 emission goals for each 

state, as well as mass-based CO2 goals that represent the 

equivalent of each state’s rate based CO2 goal, in order to 

ensure that both states and affected EGUs enjoy the maximum 

flexibility and latitude in meeting the requirements of the 

emission guidelines and that the BSER is fully implemented by 

each state. 

For its plan, a state will be able to choose to either 

impose federally enforceable emission standards that fully meet 

the emission guidelines directly on affected EGUs (the “emission 

standards” approach) or use a “state measures" approach, which 

would be composed, at least in part, of measures implemented by 
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the state that are not included as federally enforceable 

components of the plan. A state measures type plan must include 

a backstop of federally enforceable standards on affected EGUs 

that fully meet the emission guidelines and that would be 

triggered if the state measures fail to result in the affected 

EGUs achieving on schedule the required emission reductions. 

States that choose an emission standards plan must decide 

whether to adopt a plan to meet the CO2 emission performance 

rates for affected EGUs as emission standards for each EGU 

reflecting the CO2 emission performance rates that represent 

BSER. If a state adopts the CO2 emission performance rates as the 

emission standards for affected EGUs, this would satisfy the 

requirement described in section VIII.D.2.a.4 that a state 

demonstrate its plan would achieve the CO2 emission performance 

rates, and no further demonstration would be necessary. 

Alternatively, the state may elect to establish emission 

standards that are at or below the state rate- or mass-based CO2

goal for affected EGUs established in the emission guidelines. A 

state may establish emission standards for affected EGUs at 

different levels from those established in the emission 

guidelines, provided that when implemented, the emission 

standards achieve the CO2 emission performance rates or state 
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rate or mass-based CO2 emission goal set forth by the EPA for the 

state. States that adopt differential standards of performance 

among their affected EGUs must demonstrate that, in the 

aggregate, the differential standards of performance will result 

in their affected EGUs meeting the CO2 emission performance 

rates, the state’s rate-based CO2 emission goal or its mass-based 

CO2 emission goal. 

State measures plans may only be used to meet a state mass 

CO2 emission goal. Similar to emission standards plans with 

differential standards of performance, states that adopt state 

measures plans must demonstrate that the state measures, alone 

or in conjunction with any federally enforceable emission 

standards also included in the state plan, will result in the 

affected EGUs in the state meeting the state’s mass-based CO2

emission goal. 

The timing of the reductions within the interim period, 

which is laid out in section V as part of the determination of 

the BSER, may be adjusted by the state, provided that the 

interim and final CO2 emission performance rates or state CO2

emission goals are met. The EPA believes that it is appropriate 
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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. 

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 overburdened 

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 interim and final performance requirements 

included in this final rule through monitoring and reporting 

requirements. 
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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.656 

This section is organized as follows. First, we discuss the 

timeline for state plan performance and provisions to encourage 

early action. Second, we describe the types of plans that states 

can submit. Third, we summarize the components of an approvable 

state plan submittal. Fourth, we address the process and timing 

for submittal of state plans and plan revisions. Fifth, we 

address plan implementation and achievement of CO2 emission 

performance rates or state CO2 emission goals for affected EGUs, 

and the consequences if they are not met. Sixth, we discuss 

general considerations for states in developing and implementing 

plans, including consideration of a facility’s “remaining useful 

life” and “other factors” and electric reliability. Seventh, we 

note certain resources that are available to facilitate state 

plan development and implementation. Finally, we discuss 

 

656 See 40 CFR 49.1 to 49.11. 
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additional considerations for inclusion of CO2 emission reduction 

measures in state plans, including: accounting for emission 

reduction measures in state plans; requirements for rate-based 

emission trading approaches; evaluation, measurement, and 

verification (EM&V) requirements for RE and demand-side EE 

resources used to adjust a CO2 rate; and treatment of interstate 

effects and leakage. 

B. Timeline for State Plan Performance and Provisions to 

Encourage Early Action 

 This section describes state plan requirements related to 

the timing of achieving the emission guidelines and state plan 

performance periods. This section also describes the clean 

energy investment pool the EPA is establishing as part of these 

emission guidelines. 

1. Timeline for state plan performance 

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 

final guidelines establish 2030 as the deadline for compliance 

by affected EGUs with the final CO2 emission performance rates or 

CO2 rate or mass emission goal. They establish three interim 

periods—-2022-2024, 2025-2027, and 2028-2029—where increasingly 
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stringent performance rates or mass goals must be met. These 

timelines, which we explain in detail below, are based on 

careful consideration of the substantial comments we received on 

both the start date of the interim period and the trajectory of 

compliance by affected EGUs over the interim period and our 

determination of the Best System of Emission Reduction, 

discussed in Section V above, and respond to concerns about, 

among other things, reliability, feasibility, and cost. 

As previously discussed, the EPA has determined that the 

BSER includes implementation of reduction measures over the 

period of 2022 through 2029, with final compliance by affected 

EGUs in 2030. Therefore the final rule requires that interim CO2

emission performance rates or rate or mass 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 states the flexibility to define an alternate 

trajectory of emission performance between 2022 and 2029 to the 

steps specified in the rule,provided that 1) the state plan 

specifies interim step goals and 2) that meeting the statedetermined interim step goals will result in the interim state 

CO2 emission goal being met on an 8-year average or cumulative 

basis, and, further, that the 2030 state CO2 emission goal is 
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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 period –first for planning, then for 

implementation – provides states with substantial flexibility 

regarding methods and timing of achieving emission reductions 

from affected EGUs. States may wish to make adjustments to their 

implementation approaches between the time they submit their 

plans and the end of the interim plan period through a plan 

modification as appropriate, or as conditions change, they may 

need to make adjustments to ensure that their plans achieve the 

CO2 emission performance rates or state CO2 emission goals as 

intended. As a result, the agency envisions that the EPA, states 

and affected EGUs will have an ongoing relationship in the 

course of implementing this program. The EPA believes that 

timing flexibility in implementing measures provides significant 

benefits that allow states to develop plans that will help 

achieve a number of goals, including, but not limited to: 

reducing cost, addressing reliability concerns, addressing 
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concerns about stranded assets, and facilitating the integration 

of meeting the emission guidelines and compliance by affected 

EGUs with other air quality and pollution control obligations on 

the part of both states and affected EGUs. 

 The EPA received numerous comments regarding the concept 

of the interim period, including comments supporting the 

flexibility afforded states in developing their plans and the 

timing necessary to meet the 2030 emission requirements. Some 

commenters supported beginning the interim goal plan period at 

2020. Others stated that the investments necessary to meet the 

proposed interim emission performance goals beginning in 2020 

are unachievable in that timeframe or would place too great a 

burden on affected EGUs, states, and ratepayers. Some suggested 

that the 2020 interim goal step should be eliminated in favor of 

later start dates, including 2022, 2025, or other years. Other 

commenters provided input suggesting that states be allowed to 

establish their own set of emission performance steps during the 

interim plan performance period and thereby control their own 

emission reduction trajectory or “glide path” for achievement of 

the interim goal and the 2030 goal, or that the EPA not 

establish any interim standards at all. Commenters also noted 

that for some states, there was not a significant difference 
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between the interim and final goal, and, therefore, no 

significant glide path for those states that did not go below 

the 2030 final targets in the out years. 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 establish their own 

emission performance trajectory during the interim period. 

 As noted, the EPA has determined that the interim 

compliance period should start in 2022 instead of 2020, as we 

proposed, because of the substantial amount of comment and data 

we received reflecting that states and utilities reasonably 

needed that additional time to take the steps necessary to start 

achieving reductions. In order to assure the EPA and the public 

that states are making progress in implementing the plan between 

the time of the state plan submittal and the beginning of the 

interim period, and as discussed in further detail in section 

VIII.D, the final rule requires that the state plan submittal 

include a timeline with all the programmatic milestone steps the 

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

2022 to ensure the plan is effective as of 2022. 

2. Provisions to encourage early action 

 Many commenters supported providing incentives for states 
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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 recognize these activities, in the context of 

both mass-based and rate-based plans. States will be able to 

take advantage of the impacts of early investments that occur 

prior to the beginning of a plan performance period and realize 

CO2 emission reductions during the interim and final plan 

periods: from 2022 onward. Under a mass-based plan, those 

impacts will be reflected in reductions in the reported CO2

emissions of affected EGUs during the plan performance period. 

Under a rate-based plan, states may recognize early actions 

implemented after 2012 by crediting MWh of electricity 

generation and savings that are achieved by those measures 

during the interim and final plan performance periods. These 

provisions are addressed in section VIII.K.a. 

 Other commenters pointed out that to the extent that states 

and utilities would benefit from greater availability of lowcost RE and other zero-emitting generation options during the 

interim and final plan periods, the EPA should include 

provisions in the final emission guidelines that accelerate 

deployment of RE and other zero- and low-emitting resources. In 
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order to encourage early investments in RE and demand-side EE 

before the start of the interim performance period in 2022, the 

EPA is establishing a clean energy investment pool as part of 

the emission guidelines. Through this pool, the EPA intends to 

make additional ERCs and allowances available to qualified 

providers that make investments in RE and demand-side EE before 

2022. 

 The clean energy investment pool will be administered by 

the EPA and, recognizing that low-income communities are often 

under-represented in RE and demand-side EE investment, will 

place particular emphasis on these communities by including a 

sizable community reserve to drive these types of investments in 

low-income communities. The EPA will make awards based upon a 

demonstration of quantified and verified MWh of zero-emitting 

generation or energy savings realized before 2022. An affected 

EGU may use these ERCs or allowances to demonstrate compliance 

with its emission standard, regardless of whether the state in 

which the EGU is located is implementing a state plan, or the 

EPA is implementing a federal plan on behalf of the state. 

 The EPA intends to conduct a future rulemaking and 

associated outreach process to seek comment on potential 

features of the clean energy investment pool. Features about 
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which the EPA may solicit comment include whether to limit the 

size of the investment pool and what an appropriate limit might 

be; the appropriate size of the community reserve, and whether 

there should be a mechanism to increase the size of the 

community reserve if it is oversubcribed; the procedures and 

requirements for distributing ERCs and allowances from the clean 

energy investment pool; the types of RE and demand-side EE 

projects that might qualify for the investment pool; and the 

priorities and concerns the agency should focus on in 

distributing the community reserve. 

 The clean energy investment pool will provide a number of 

benefits. First, the investment pool will provide affected EGUs 

and states with additional resources to help them achieve their 

state plan obligations. Second, the pool will improve the 

liquidity, in the early years of the program, of the ERC and 

allowance markets we expect to emerge for compliance with the 

requirements of these guidelines. In addition, the clean energy 

investment pool will provide incentives designed to reduce 

energy bills early in the program through earlier and broader 

application of demand-side EE, and help ensure that these 

benefits are shared with low-income communities. Finally, the 

EPA believes that stimulating or supporting early investment in 
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RE generation technologies could accelerate the rate at which 

the costs of these technologies fall over the course of the 

interim performance period. 

 The clean energy investment pool will enable qualified 

providers to earn ERCs or allowances in exchange for investments 

in RE and demand-side EE made during the years following the 

promulgation of these emission guidelines and before 2022 that 

result in quantified and verified MWh of zero-emitting 

generation and energy savings during those years. A qualified 

provider might include an affected EGU, a state, or an 

independent investor in an RE or demand-side EE project, among 

others. 

 In the case of qualified provider that has invested in a 

state implementing a rate-based state plan approach, the EPA 

would award MWh from the investment pool, which may be converted 

into ERCs according to the formula outlined below, to the 

provider. An affected EGU or could use these ERCs to demonstrate 

compliance with its rate-based emission standard. In the case of 

a qualified provider that has invested in a state implementing a 

mass-based state plan approach, the EPA would award MWh from the 

investment pool, which may be converted into allowances 

according to the formula outlined below, to the provider. These 
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allowances are supplemental to the state’s mass-based CO2

emission goal. An affected EGU could use these allowances to 

demonstrate compliance with its mass-based emission standard. 

 The clean energy investment pool is designed as a 

transitional mechanism in the early years of implementation of 

the 111(d) emission guidelines. As a result, the EPA is 

considering limiting the size of the investment pool. This 

approach is similar in design to the compliance supplement pool 

(CSP) included in the NOx SIP call, which was also limited in 

size.657 The EPA intends to set aside a portion of the MWh in the 

investment pool in a community reserve, designed to drive 

investments in RE and demand-side EE projects that benefit lowincome communities. 

 Upon such time the EPA distributes the MWh from the 

investment pool to a qualified provider, the EPA may convert 

these MWh into ERCs or allowances, depending on whether the 

project is in a state with a rate-based or mass-based plan. To a 

qualified provider implementing a project in a state with a 

rate-based state plan, the EPA may award one ERC for every two 

MWh of quantified and verified RE or demand-side EE realized 

 

657 65 FR 2727 (January 18, 2000), as amended at 71 FR 74795 

(December 13, 2006). 
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during the period following the promulgation of these emission 

guidelines and before 2022, as a result of its investment made 

during this period. To a qualified provider implementing a 

project in a state with a mass-based state plan, the EPA may 

award a number of allowances equivalent to the quantified and 

verified MWhs realized during the period following the 

promulgation of these emission guidelines and before 2022, 

divided by two and multiplied by the state’s CO2 emission rate 

goal. The EPA intends to solicit comment on this two for one 

distribution requirement in a future rulemaking, including 

whether this requirement might differ for for qualified 

providers implementing projects that demonstrate benefits to one 

or more low-income communities. The EPA intends to distribute 

MWh from the investment pool to qualified providers on a firstcome first-served basis, based upon the date and time that the 

EPA receives the project application. 

 A qualified provider may submit a project application to 

the EPA at any time prior to the implementation of the project. 

The EPA intends to implement a process for project approval that 

is similar to the two-step process for ERC issuance included in 

these emission guidelines. First, an affected EGU will submit a 

project application to the EPA, which includes (1) a 
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demonstration that the project meets the eligibility 

requirements defined by the EPA; (2) an EM&V plan that outlines 

how the MWh results of the project will be quantified and 

verified, and which adheres to the EM&V requirements included in 

these final emission guidelines. The project application must be 

reviewed by an accredited independent third party verifier 

before it is submitted to the EPA. 

 In addition, if a provider wishes to qualify for ERCs or 

allowances from the community reserve, it must demonstrate in 

the project application the benefit the project will have to one 

or more low-income communities. This benefit may be in the form 

of MWh provided to the low-income community, financial proceeds 

from the project primarily benefiting the low-income community, 

or the project lowering utility costs of low-income rate-payers. 

In step two of the ERC issuance process, after the 

qualified provider has implemented the project, it submits to 

the EPA a monitoring and verification report that documents the 

quantified and verified MWh of eligible RE generation or demandside EE savings realized during the years following the 

promulgation of these emission guidelines and before 2022. This 

report must be reviewed by an accredited independent third party 

verifier before it is submitted to the EPA. The EPA would review 
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this report and, if approved, award to the project provider a 

number of MWh from the state’s investment pool account, which 

may be converted into ERCs or allowances according to the 

formulas described above. An affected EGU may then use these 

ERCs or allowances to demonstrate compliance with its emission 

standard. 

C. State Plan Approaches 

[Note to readers: the legal discussions in this section VIII.C 

have been consolidated into one section at the end] 

1. Overview

 Under the final emission guidelines, states may adopt and 

submit either of two different types of state plans. The first 

would apply all requirements for meeting the emission guidelines 

to affected EGUs in the form of federally enforceable emission 

standards.658 We refer to this as an “emission standards” state 

 

658 40 CFR 60.21(f) defines “emission standard” as “a legally 

enforceable regulation setting forth an allowable rate of 

emissions into the atmosphere, establishing an allowance system, 

or prescribing equipment specifications for control of air 

pollution emissions.” This definition is promulgated and 

effective, and we note that it authorizes the use of allowance 

systems as a form of emission standard. To resolve any doubt 

that allowance systems are an acceptable form of emission 

standard in the Clean Power Plan, we are including regulatory 

text in the final subpart UUUU regulations authorizing the use 

of allowance systems as a form of emission standard under 

section 111(d). Section 60.21(f) was originally amended in 2005 

to include recognition of allowance systems as a form of 

emission standard in the Clean Air Mercury Rule (CAMR) (70 FR 
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plan type. The second, which we refer to as a “state measures” 

plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state 

measures659 that apply to affected EGUs, other entities, or some 

combination thereof. The state measures plan type also includes 

a mandatory contingent backstop of federally enforceable 

emission standards for affected EGUs that would apply in the 

event the plan does not achieve its anticipated level of 

emission performance as specified in the state plan during the 

 

28606, 28649; May 18, 2005). CAMR was vacated in its entirety in 

New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). However, the 

reason for vacatur was wholly unrelated to the question of 

whether an allowance system could be a form of emission 

standard. In response to the New Jersey decision, the agency 

removed CAMR provisions from the Code of Federal Regulations. 

The agency chose to retain the language of 60.21(f) and 

60.24(b)(1) generally recognizing allowance systems. This 

language is broader than CAMR and unrelated to the reasons for 

its vacatur. The EPA re-promulgated these provisions in February 

of 2012 (77 FR 9304, 9447; Feb. 16, 2012). Even if this were not 

the case, the agency would not concede that simply because 

“allowance systems” were not provided for in the framework 

regulations of subpart B, they could not be relied upon in 

specific emission guidelines, such as these for carbon dioxide. 

The framework regulations generally serve a gap-filling role 

where there are not more specific provisions laid out in the 

relevant emission guidelines. In order to resolve any question 

whether allowance systems are authorized under the Clean Power 

Plan, we are including regulatory text in subpart UUUU to make 

this authorization explicitly clear. 

659 “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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period that the state is relying on state measures. The 

inclusion of a backstop of federally enforceable emission 

standards in a state measures plan type is legally necessary for 

a state plan to meet the requirements of 111(d), which 

specifically require a state to submit standards of 

performance.. 

 These two types of state plans and their respective 

approaches, either of which could be implemented on a singlestate or multi-state basis, allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. Further, as described in 

detail below, both types of plans are responsive to comments we 

received from states and other stakeholders. 

In addition to providing states the option of developing an 

emission standards or state measures type plan, the final 

rule makes clear that states that choose an emission 

standards plan can adopt either a rate-based or mass-based 

CO2 emission goal. Further, the EPA notes that if a state 

chooses the option of meeting a state rate or mass CO2
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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 using an 

emission standards plan could potentially adopt mass-based 

emission standards for its affected EGUs and/or other 

measures and demonstrate that its plan will achieve its 

rate-based CO2 goal. Likewise, a state could adopt ratebased emission standards and/or other measures and 

demonstrate that its plan will meet its mass-based CO2

goal.2. “Emission standards” state plan type

The emission standards type of state plan imposes 

requirements solely on affected EGUs in the form of federally 

enforceable emission standards. This type of state plan, as 

described below, may consist of rate-based emission standards 

for affected EGUs or mass-based emission standards for affected 

EGUs. 

The state plan submittal for an emission standards type 

plan must demonstrate that these federally enforceable emission 

standards for affected EGUs will achieve the CO2 emission 

performance rates or the applicable rate-based or mass-based 

state CO2 emission goal. 
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Both rate-based and mass-based emission standards included 

in a state plan must be quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These requirements are described 

in more detail at section VIII.D.2. 

Rate-based and mass-based emission standards may 

incorporate the use of emission trading, as described below. The 

EPA anticipates the use of emission trading in state plans, 

given the advantages of this approach and comments suggesting a 

high degree of interest on the part of states, utilities, and 

independent power producers in the inclusion of emission trading 

in state plans.660

 The EPA notes it is proposing model rules for both massbased and rate-based emission trading programs. States that 

adopt and submit the finalized model rules for either emission 

trading program will be presumptively approvable as meeting the 

requirements of CAA section 111(d) and these emission 

guidelines. States that adopt and submit the proposed model rule 

for either the mass-based or rate-based emission trading program 

would be presumptively approvable through the conditional 

approval mechanism, which the EPA intends to adopt through this 

 

660 The legal basis for authorizing trading in emission standards 

is discussed in section VIII.C.6. 
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upcoming rulemaking. The conditional approval mechanism is 

intended to parallel the mechanism provided under CAA section 

111(k)(4). Under the conditional approval mechanism, states that 

adopt and submit the proposed model rule(s) would have an 

obligation to submit the model rule as finalized by the EPA, or 

the conditional approval of the state plan submission would 

convert to a disapproval. 

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.661 A plan could be designed such that compliance by 

 

661 States could also apply rate-based emission standards for 

affected EGUs that are designed to achieve a state’s mass-based 

CO2 goal. Under this type of approach, the state would be 

required to include a demonstration, in the state plan 

submittal, of how the affected EGUs would achieve the mass CO2

goal. This demonstration would include a projection of CO2

emissions for the fleet of affected EGUs that would result from 

application of the rate-based emission standards for affected 

EGUs. Once the plan is implemented, if the rate goal is not 

achieved for the fleet of affected EGUs as a whole, corrective 
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affected EGUs would assure achievement of either the CO2 emission 

performance rates for affected EGUs or the state rate-based CO2

emission goal. To meet the CO2 emission performance rates for 

affected EGUs, a plan would establish separate rate-based 

emission standards for affected fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines (in lb CO2/MWh) that are equal to or lower than the CO2

emission performance rates in the emission guidelines. To meet a 

state rate-based CO2 goal, a plan would establish a uniform ratebased emission standard (in lb CO2/MWh) that applies to all 

affected EGUs in the state. This uniform emission rate would be 

equal to or lower than the applicable state rate-based CO2 goal 

specified in the final emission guidelines. 

 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. 

 

measures would need to be implemented, as described in section 

VIII.F.3.
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Alternatively, if a state chose, it could 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.662 

Under this type of approach, therefore, the state would be 

required to include a demonstration,663 in the state plan 

submittal, that its plan would achieve the CO2 emission 

performance rates or applicable state rate-based CO2 goal. This 

demonstration would include a projection of the collective, 

 

662 The weighted average CO2 emission rate that will be achieved by 

the fleet of affected EGUs in a state that applies different 

rate-based emission standards to individual affected EGUs or 

groups of affected EGUs will depend upon the mix of electric 

generation from affected EGUs subject to different emission 

standards. For example, if a state applies higher emission 

standards for affected steam generating units and lower emission 

standards for affected NGCC units, the greater the projected 

amount of electric generation from steam generating units, the 

higher the projected weighted average emission rate that will be 

achieved for all affected EGUs. 

663 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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weighted average CO2 emission rate the fleet of affected EGUs 

would achieve as a result of compliance with the emission 

standards in the plan. Once the plan is implemented, if the CO2

emission performance rates or applicable state rate-based CO2

goal are not achieved, corrective measures would need to be 

implemented, as described in section VIII.F.3. 

Under a rate-based approach, a state may include in its 

plan a number of provisions to facilitate affected EGU 

compliance with the emission standards. First, a state may 

encourage (or require) EGUs to undertake actions to reduce CO2

emissions at the affected EGU level, such as heat rate 

improvements or fuel switching. These measures are discussed in 

section VIII.I. Second, a state may implement a market-based 

emission trading program, which enables EGUs to generate and 

procure Emission Rate Credits (ERCs), a tradable compliance unit 

representing one MWh of electric generation (or reduced 

electricity use) with zero associated CO2 emissions. 

Considerations and requirements for rate-based trading programs 

are discussed in section VIII.K. 

ERCs would be issued by the administering state regulatory 

body. The state may issue ERCs to affected EGUs that emit below 

a specified CO2 emission rate, as well as for measures that 
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provide substitute generation for affected EGUs or avoid the 

need for generation from affected EGUs. These ERCs may then be 

used to adjust the reported CO2 emission rate of an affected EGU 

when demonstrating compliance with a rate-based emission 

standard. For each submitted ERC, one MWh is added to the 

denominator of the reported CO2 emission rate, resulting in a 

lower adjusted CO2 emission rate. 

Eligible measures that may generate ERCs, as well as the 

accounting method for adjusting a CO2 emission rate, are 

discussed in section VIII.G.1. Requirements for rate-based 

emission trading approaches are discussed in section VIII.G.3. 

Quantification and verification requirements for measures 

eligible to generate ERCs are discussed in section VIII.G.4. 

 

(1) Rate-based emission standards based on operational or other 

standards. As discussed in further detail in section 

VIII.D.d.(3), regarding the legal considerations and statutory 

language of CAA section 111(h), the EPA is finalizing that 

design, equipment, work practice, and operational standards 

cannot be considered as “standards of performance” for this 

final rule. However, a state may elect to use emission standards 

for affected EGUs that result in a reduced CO2 lb/MWh emission 
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rate for affected EGUs because of operational or other 

standards. The state would include in its state plan an emission 

standard that is the rate standard that results from the 

applicable operational or other standard. For example, a state 

might choose to recognize that an individual affected EGU has 

plans to retire, and those plans could be codified in the state 

plan by adopting an emission standard of 0 CO2 lb/MWh as of a 

certain date. The state would thus include in the state plan an 

emission standard of 0 CO2 lb/MWh for that affected EGU that 

applies after a specified date. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any ratebased plan, the state would need to demonstrate that the plan 

would achieve the required level of emission performance for 

affected EGUs, in CO2 lb/MWh. A plan could also apply such 

emission standards to a subset of affected EGUs in the state 

while applying other rate-based emission standards to the 

remainder of affected EGUs in the state. For example, a plan 

might include an emission standard of 0 CO2 lb/MWh reflecting a 

retirement mandate for one or more affected EGUs in a state and 

apply a rate-based emission standard equal to the CO2 emission 

performance rates or a state’s rate-based CO2 emission goal to 
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the remainder of affected EGUs. 

As with all emission standards, emission standards based on 

design, equipment, work practice, and operational standards must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. 

(2) Additional considerations for rate-based approach. 

Additional considerations and requirements for rate-based 

emission standards state plans are addressed in section VIII.K. 

This includes the basic accounting method for adjusting the 

reported CO2 emission rate of an affected EGU, as well as 

requirements for the use of measures to adjust a CO2 emission 

rate, both of which are discussed in sections VIII.K.1 through 

4. Such requirements include eligibility, accounting, and 

quantification and verification requirements (EM&V) for the use 

of CO2 emission reduction measures that provide substitute 

generation for affected EGUs or avoid the need for generation 

from affected EGUs in rate-based state plans. Section VIII.K.5 

addresses multi-state coordination among rate-based emission 

trading programs. 

b. Mass-based approach. The second “emission standards” approach 

a state may elect to use is mass-based emission standards 
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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 

VII). States could also apply mass emission standards for 

affected EGUs that are designed to achieve a state’s rate-based 

goal.664 

 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 

 

664 Under this type of approach, the state would be required to 

include a demonstration, in 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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EGUs. One pathway a state could take to achieve its mass-based 

CO2 goal would be to apply mass-based emission standards to 

individual affected EGUs, in the form of a limit on total 

allowable CO2 emissions. These emission standards would be 

designed such that total allowable CO2 emissions from all 

affected EGUs in a state are equal to or less than the state’s 

mass-based CO2 goal. 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. 

 

 

(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 
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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 

up to the established emission budget.665 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. 

The EPA views an emission budget trading program as a 

highly efficient, market-based approach for reducing CO2

emissions from affected EGUs. Such programs include a limit on 

mass CO2 emissions while providing both short-term and long-term 

price signals that encourage the owners or operators of affected 

EGUs, as well as other entities, to determine the most efficient 

means of achieving the mass emission limit. Notably, such an 

 

665 An emission allowance represents a limited authorization to 

emit, typically denominated in one short ton or metric ton of 

emissions. 
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approach incents actions taken at affected EGUs to reduce CO2

emissions, as well as the use of strategies such as RE and 

demand-side EE as complementary measures that reduce CO2

emissions. However, unlike under a rate-based approach, for this 

latter set of measures there is no need to address and describe 

these state measures in a state plan submission or quantify and 

verify the RE and EE MWh of generation and savings. As a result, 

a mass-based emission budget trading program incents and 

recognizes a wide range of emission reduction actions while 

being relatively simple for a state to implement and administer. 

Furthermore, the EPA notes that such an approach still allows 

for a state to address electricity load growth, as load growth 

can be met through low- and non-emitting generating resources, 

as well as avoided through demand-side energy efficiency and 

demand-side management measures. 

Additional considerations and requirements for mass-based 

emission standards state plans are addressed in section VIII.J. 

This includes use of emission budget trading programs in a state 

plan, including provisions required for such programs (section 

VIII.J.2.a) and the design of such programs in the context of a 

state plan. This section addresses program design approaches 

that ensure achievement of a state mass-based CO2 emission goal 
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(section VIII.J.2.b), as well as how states can use emission 

budget trading programs with broader source coverage and other 

flexibility features in a state plan, such as the programs 

currently implemented by California and the RGGI participating 

states (section VIII.J.2.c). Section VIII.J.2.d addresses other 

considerations for the design of emission budget trading 

programs that states may want to consider, such as allowance 

allocation approaches. Section VIII.J.3 addresses multi-state 

coordination among emission budget trading programs used in 

states that retain their individual state mass-based CO2 goals. 

(3) Mass-based emission standards based on operational or other 

standards. As discussed in section VIII.C.2.a.(1) above, a state 

may elect to use mass-based emission standards for affected EGUs 

that result in a reduced total tonnage of CO2 emissions from 

affected EGUs because of operational or other standards. The 

state would include in its state plan an emission standard that 

is the mass standard that results from the applicable 

operational or other standard. For example, a state might choose 

to recognize that an individual affected EGU has plans to 

retire, and those plans could be codified in the state plan by 

adopting an emission standard of 0 total tons of CO2, as of a 

certain date. The state would thus include in the state plan an 
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emission standard of 0 total tons of CO2 for that affected EGU 

that applies after a specified date. Under a mass-based 

approach, the state could also include an emission standard 

(e.g., a mass limit) that reflects the result of a limit on an 

affected EGU’s total operating hours over a specified period. 

Such an emission standard would be based on an affected EGU’s 

potential to emit given a specified number of operating hours. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any massbased plan, the state would need to demonstrate that the plan 

would achieve the required level of emission performance for 

affected EGUs, in total tons of CO2. A plan could also apply such 

emission standards to a subset of affected EGUs in the state 

while applying other emission standards to the remainder of 

affected EGUs in the state. For example, a plan might include an 

emission standard of 0 tons of CO2 for one or more affected EGUs, 

reflecting a retirement mandate for one or more affected EGUs in 

a state, and include the remainder of affected EGUs in an 

emission budget trading program. 

3. “State measures” state plan type 

 The second type of state plan is what we refer to as a 

“state measures” plan. As previously discussed, the EPA believes 
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states will be able to submit state plans under the emission 

standards plan type, and its respective approaches, and achieve 

the CO2 emission performance rates or rate-based or mass-based 

state CO2 goals by imposing federally enforceable requirements on 

affected EGUs. Upon further consideration of the requirements of 

CAA section 111(d), in consideration of the comments we received 

on the proposed portfolio approach the state commitments 

approach, and in order to provide flexibility and choice to 

states that may wish to adopt a plan that does not place all the 

obligations on affected EGUs, the EPA is finalizing the state 

measures plan type in addition to the emission standards plan 

type. The EPA believes the state measures plan type will provide 

states with additional latitude in accommodating existing or 

planned programs that involve measures implemented by the state, 

or by entities other than affected EGUs, that result in avoided 

generation and CO2 emission reductions at affected EGUs. This 

includes market-based emission budget trading programs that 

apply, in part, to affected EGUs, such as the programs 

implemented by California and the RGGI participating states in 

the Northeast and Mid-Atlantic, as well as RE and demand-side EE 

requirements and programs, such as renewable portfolio standards 

(RPS), energy efficiency resource standards (EERS), and utility- 
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and state-administered incentive programs for the deployment of 

RE and demand-side EE technologies and practices. The EPA 

believes this second state plan type will afford states with 

appropriate flexibility while meeting the statutory requirements 

of CAA section 111(d). 

Measures implemented under the state measures plan type 

could include RE and demand-side EE requirements and deployment 

programs. This type of plan could align with existing state 

resource planning in the electricity sector, including RE and 

demand-side EE investments by state-regulated electric 

utilities. The state measures plan type also can accommodate 

emission budget trading programs that address a broader set of 

emission sources than just affected EGUs subject to CAA section 

111(d), such as the programs currently implemented by California 

and the RGGI participating states. The EPA also notes that the 

state measures plan type could accommodate imposition by a state 

of a fee for CO2 emissions from affected EGUs, an approach 

suggested by a number of commenters. 

 This plan type would allow the state to implement a suite 

of state measures that are adopted, implemented, and enforceable 
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only under state law, and rely upon such measures666 in achieving 

the required level of CO2 emission performance from affected 

EGUs. The state measures under this plan type could be measures 

involving entities other than affected EGUs, or a combination of 

such measures with emission standards for affected EGUs, so long 

as the state demonstrates that such measures will result in 

achievement of a state’s mass-based CO2 goal, as discussed below. 

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 

alone or state measures in conjunction with any federally 

enforceable emission standards, will achieve the state massbased CO2 goal for affected EGUs.667 However, because the state 

 

666 “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. 

667 If a state is implementing a rate-based plan, this 

demonstration is based on projected CO2 mass emissions from 

affected EGUs. However, a state could propose in its plan a 

method to adjust these projected mass CO2 emissions from affected 
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measures would not be federally enforceable emission standards, 

the plan must also include a “backstop” of federally enforceable 

emission standards for all affected EGUs, in order for the state 

measures plan type to satisfy the requirement of CAA section 

111(d) that a state establish standards of performance for 

affected EGUs. This backstop would impose federally enforceable 

emission standards on the state’s affected EGUs in the case that 

the state measures fail to achieve the state mass-based CO2

goal. The backstop, discussed further below, would assure that 

the state mass-based CO2 goal is fully achieved by affected EGUs 

in the form of federally enforceable emission standards. 

a. Requirements for state measures under a state measures type 

plan. Under the state measures plan type, state measures must be 

satisfactorily described in the supporting material for a state 

plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission 

 

EGUs, based on the projected results of its rate-based state 

measures, when demonstrating that a plan will achieve the state 

mass-based CO2 goal. The appropriateness of the proposed 

adjustment method would be reviewed by the EPA as part of its 

review of the plan. If a state proposes such an adjustment 

method, and it is approved by the EPA, the state must use the 

same adjustment method when demonstrating that the plan achieved 

the state mass-based CO2 goal.
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standards. Specifically, the state plan submittal must 

demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 

 The EPA would assess the overall approvability of state 

measures type plan using based, in part, on the state’s 

satisfactory demonstration that the state measures, in 

conjunction with any federally enforceable emission standards on 

the affected EGUs that might be included in the plan, would 

result in the state plan’s achievement of the mass-based CO2 goal 

for the state’s affected EGUs. 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 state mass-based CO2 goal 

for affected EGUs. 
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 The EPA’s evaluation of the approvability of a state 

measures plan would also include an assessment of whether the 

backstop composed of federally enforceable emission standards 

for the state’s affected EGUs would assure that the state massbased CO2 goal is fully achieved by affected EGUs, in the case 

that the state measures fail to achieve the state mass-based CO2

goal. The trigger for the backstop must also satisfactorily 

provide for the implementation of the backstop emission 

standards. 

b. Considerations for the backstop included in a state measures 

type plan. As further discussed in section VIII.C.4.c, the EPA 

believes a backstop, composed of federally enforceable emission 

standards for the affected EGUs that are sufficient to achieve 

the state mass-based CO2 goal 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 
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emission standard requirements, which must be quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 

 These federally enforceable emission standards must be 

designed such that compliance by affected EGUs with the emission 

standards would achieve the state’s mass-based interim and final 

goals for affected EGUs. The emission standards must specify CO2

emission performance levels (in mass) that would apply for the 

interim plan performance period (including specifying levels for 

each of the interim step 1 through step 3 periods) and the final 

two-year plan performance periods.668 If a state chose, these 

backstop emission standards could be based on a model rule 

promulgated by the EPA.669

 

 

 The state measures plan must specify the trigger and 

conditions under which the backstop federally enforceable 

emission standards would apply. The trigger and attendant 

 

668 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). 

669 [Insert reference to FP/state plan model rule co-proposal.] 
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conditions for deployment of the backstop would address the CAA 

section 111(d) requirement that states submit a program for the 

implementation of standards of performance. The state measures 

plan must specify the level of emission performance that will be 

achieved by affected EGUs as a result of implementation of the 

state measures plan during the interim and final plan 

performance periods. This includes the level of emission 

performance during the interim plan periods 2022-2024, 2025-2027 

and 2028-2029, as well as the performance level that would be 

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 level of 

emission performance specified in the plan 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 
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VIII.D.2.c.670 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. 

 The backstop emission standards must make up for any 

shortfall in CO2 emission performance during a prior plan 

performance period that led to triggering of the backstop. The 

state may address the requirement to make up for any shortfall 

in CO2 emission performance by submitting, as part of the final 

plan, backstop emission standards that assure affected EGUs 

would achieve the state’s mass-based interim and final CO2 goals 

for affected EGUs, and then later submit appropriate revisions 

to the backstop emission standards adjusting for the shortfall 

through the state plan revision process. The state may also 

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 

 

670 States may choose to establish an effective date for backstop 

emission standards that is sooner than 18 months. 
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to address the emission performance shortfall. 

 For example, assume a plan identified a mass-based CO2 

standard for affected EGUs of 100 million tons during the 

interim step 1 performance period (2022-2024), 90 million tons 

during the interim step 2 performance period (2025-2027), and 80 

million tons during the interim step 3 performance period (2028-

2029. Over the entire interim plan performance period (2022-

2029), the interim mass-based CO2 goal is cumulative emissions of 

270 million tons. Assume that CO2 emissions from affected EGUs in 

the interim step 1 period were actually 115 million tons, 

triggering implementation of the backstop. In this instance, the 

mass-based standard for affected EGUs implemented as part of the 

backstop during subsequent plan performance periods would need 

to ensure that cumulative CO2 emissions during the 2022-2029 

interim period do not exceed 270 million tons. This could be 

achieved, for example, by implementing a mass standard of 75 

million tons during the interim step 2 performance period 

(rather than the 90 million tons originally specified in the 

plan), or some other combination during the remaining interim 
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step 2 and 3 performance periods.671 The emission standards 

included in the plan must specify calculations for how such 

adjustments will be made. 

 

4. Summary of comments on state plan approaches 

The EPA received a wide range of comments on the basic plan 

approaches in the proposal. Numerous commenters supported 

providing states with the option of implementing a rate-based or 

mass-based approach. Some commenters expressed concern that a 

rate-based approach would not reduce overall emissions, and 

could actually lead to increased emissions. The EPA does not 

agree with this latter comment, because both approaches would 

result in adequate and appropriate constraints on CO2 emissions. 

As documented in the RIA, a rate-based approach would result in 

a substantial reduction in CO2 emissions relative to emissions 

under a business-as-usual case. 

 Numerous commenters supported allowing states to implement 

a rate-based emission standard approach applied to affected 

EGUs. There was also broad support in comments for allowing 

 

671 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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states to pursue a mass-based approach in the form of mass 

emission standards on affected EGUs. The EPA is finalizing both 

of these approaches. 

 The EPA received a mix of comments for and against the 

proposed portfolio approach, in which state requirements and 

other measures that apply to non-EGU entities would be part of a 

state’s federally enforceable state plan. Multiple commenters 

supported the portfolio approach because it would align with 

existing state and utility planning processes in the electric 

power sector, and would maximize state discretion and 

flexibility in developing plans. Commenters mentioned the range 

of state requirements and utility programs overseen by states 

that could be used under a portfolio approach and result in 

achieving the CO2 emission goal for affected EGUs, including 

state RPS, EERS and utility-administered EE programs. Commenters 

noted that the portfolio approach would provide states maximum 

flexibility to take local circumstances, economics and state 

policy into account when developing their plans. 

 By contrast, multiple commenters opposed the portfolio 

approach. Some commenters questioned how a portfolio approach 

would work, and whether the EPA had provided sufficient detail 

explaining how such a plan approach could be implemented by a 
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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).672 Multiple commenters expressed concern 

about making state requirements and utility programs for RE and 

demand-side EE enforceable under the CAA. Some of these 

commenters supported the state commitments plan approach that 

the EPA took comment on in the proposal, which was a variant of 

the portfolio approach. Under the state commitment variant, 

measures that applied to entities other than affected EGUs would 

not be federally enforceable under the CAA, but state 

commitments to implement those measures would be federally 

enforceable elements of a state plan under the CAA. 

 After considering these comments, the EPA is not finalizing 

the portfolio approach or the state commitment variant. However, 

the EPA is finalizing the state measures plan type, as described 

above, which would accommodate state choices and allow states to 

rely upon a variety of measures, as was envisioned under the 

portfolio approach, in a way that meets the statutory 

requirements of CAA section 111(d). 

 

672 Legal concerns with the proposed portfolio approach are 

explored in section VIII.C.4.d. 
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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. 

 The EPA is finalizing two approaches that allow states to 

coordinate implementation in order to meet the emission 
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guidelines.673

 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.674 

 States have the option to implement this second approach in 

 

673 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. 

674 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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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 would allow states to 

implement a multi-state plan to meet a joint CO2 emission goal. 

However, a number of states commented that states should also be 

allowed to coordinate without aggregating multiple individual 

state goals into a single joint goal. Many states questioned the 
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incentives that a state would have to aggregate its goal with 

other states that have different goals, and also noted the 

administrative complexities presented by states seeking to 

formally coordinate state plans with one another. 

 The EPA notes that there are multiple incentives for states 

to collaborate by implementing a multi-state plan to meet an 

aggregated joint goal, regardless of the specific level of their 

individual goals, because states share grid regions and impacts 

from plan implementation will be regional in nature. Further, 

multiple analyses, including those by ISOs and RTOs, indicate 

that regional approaches could achieve state goals at lesser 

cost than individual state plan approaches. However, the EPA 

also recognizes the value in allowing for collaboration where 

states retain individual goals. These approaches could provide 

some of the benefits of a joint goal while reducing the 

negotiations among states necessary to develop a multi-state 

plan with a joint goal. As a result, the EPA has finalized the 

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 
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to join or form regional market-based programs. Many commenters 

touted the economic efficiency benefits of such approaches, and 

noted that such programs have features that support electric 

reliability. 

 The EPA agrees with these comments, and notes that it 

encouraged such approaches in the proposal. While the EPA is not 

requiring states to join and/or form regional market-based 

programs, we note that such programs can be helpful for many 

reasons, including features that support reliability. Marketbased programs allow greater flexibility for affected EGUs both 

in the short-term and long-term. Under a market-based program, 

affected EGUs have the ability to obtain sufficient allowances 

or credits to cover their emissions in order to comply with 

their emission limits. Additionally, we continue to encourage 

states to cooperate regionally. Regional cooperation in planning 

and reliability assessments is an important tool to meeting 

system needs in the most cost-effective, efficient, and reliable 

way. 

b. Multistate coordination through a joint emission goal. 

Multiple states may submit a multi-state plan that achieves an 

aggregated joint CO2 emission goal for the affected EGUs in the 
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participating states.675 The joint emission goal approach is 

acceptable for both types of state plans, the “emission 

standards” plan type and the “state measures” plan type. 

However, the EPA is requiring that a joint goal may apply only 

to states implementing the same type of plan, either an 

“emission standards” plan or a “state measures” plan.676 

 Under this approach, a rate-based multi-state plan would 

 

675 As a conceptual and legal matter, the relationship between 

states coordinating to meet a joint CO2 emission goal under this 

rule is similar to the relationship between states coordinating 

SIP submissions to attain the NAAQS in an interstate 

nonattainment area. In both cases, the states coordinate their 

actions in a way that, cumulatively, the measures applicable in 

each state will lead to achievement of a common interstate goal 

(with the EPA evaluating the sufficiency and success of the 

plans on a holistic, interstate basis). Despite the shared goal, 

in both cases, the mere fact of coordination has no effect on 

each state’s sovereign legal authority. For example, the legally 

applicable rules in a given state are adopted by that state 

individually, not by a joint entity or other interstate 

mechanism. Similarly, the fact that the states coordinate their 

rules does not grant them the authority to directly enforce each 

other’s rules, or to take direct legal action against a state 

that is failing to implement its own rules. Although some states 

may jointly submit their coordinated rules to the EPA as a 

matter of administrative convenience, the state rules within 

such a plan are nothing more than reciprocal laws of the sort 

that states routinely enact in voluntary coordination with each 

other. 

676 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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include a weighted average rate-based emission goal, derived by 

calculating a weighted average CO2 emission rate based on the 

individual rate-based goals for each of the participating states 

and 2012 generation from affected EGUs. A mass-based multi-state 

plan would include an aggregated mass-based CO2 emission goal for 

the participating states, in cumulative tons of CO2, derived by 

summing the individual mass-based CO2 emission goals of the 

participating states. 

 Such plans could include emission standards in the form of 

a multi-state rate-based or mass-based emission trading 

program.677 Alternatively, states could submit a multi-state plan 

using a state measures approach.678 Both approaches could provide 

for implementation of a multi-state rate-based or mass-based 

emission trading program. 

 

677 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. 

678 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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c. Multi-state coordination among states retaining individual 

state goals. States that do not wish to pursue a joint CO2

emission goal with other states may pursue a second pathway to 

multi-state collaboration. States may submit individual plans 

that will meet the CO2 emission performance rates or a state mass 

CO2 goal for affected EGUs, but include implementation in 

coordination with other state plans by providing for the 

interstate transfer of ERCs or CO2 allowances, depending on 

whether the state is implementing a rate-based or mass-based 

emission trading program. This form of coordinated 

implementation may occur under both an “emission standards” type 

of plan and a “state measures” type of plan, where states are 

implementing rate-based or mass-based emission trading 

programs.679 For rate-based plans, this type of coordinated 

approach is limited to state plans with rate-based emission 

standards that are equal to the CO2 emission performance rates in 

the emission guidelines. 

 Under this approach, a state plan could indicate that ERCs 

or CO2 allowances issued by other states with an EPA-approved 

 

679 ERCs may only be transferred among states implementing ratebased emission limits. Likewise, emission allowances may only be 

transferred among states implementing mass-based emission 

limits. 
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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,680 through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.681 

 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.682 However, the EPA 

would also assess linkages with other state plans, to ensure 

 

680 Referred to in different programs as “surrender,” 

“retirement,” or “cancellation.” 

681 The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading programs. The EPA 

is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality.

682 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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that the joint tracking system or interoperable tracking systems 

used to implement rate-based or mass-based emission trading 

programs across states are properly designed with necessary 

components, systems, and procedures to maintain the integrity of 

the linked emission trading programs. 

 Coordinated state plan implementation among states that 

retain individual state mass-based CO2 goals (or that implement 

individual state plans with rate-based emission standards 

consistent with the CO2 emission performance rates in the 

emission guidelines) is discussed in more detail in sections 

VIII.J and K. Section VIII.J discusses coordinated 

implementation among states implementing individual mass-based 

emission budget trading programs and section VIII.K discusses 

coordinated implementation among states implementing individual 

rate-based emission trading programs. [Will add more text here 

on substance addressed in these sections.] 

d. Multi-state plans that address a subset of EGUs in a state. 

The EPA is clarifying in the final emission guidelines that a 

state may participate in more than one multi-state plan. Under 

this approach, the state would identify in its submittal the 

subset of affected EGUs in the state that are subject to the 

multi-state plan or plans. This could involve a subset of 
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affected EGUs that are subject to a multi-state plan, with the 

remainder of affected EGUs subject to a state’s individual plan. 

Alternatively, different affected EGUs in a state may be subject 

to different multi-state plans. In all cases, the state would 

need to identify in each specific plan which affected EGUs are 

subject to such plan, with each affected EGU subject to only one 

multi-state plan or subject only to the state’s individual plan 

(if relevant). 

 These scenarios may occur where a state chooses to cover 

affected EGUs in different ISOs or RTOs in different multi-state 

plans. This will provide states with flexibility to participate 

in multi-state plans that address the affected EGUs in a 

respective grid region, in the case where state borders cross 

grid regions. 

 These scenarios may also occur where a state is served by 

multiple vertically integrated electric utilities with service 

territories that cross state lines. This will provide states 

with flexibility to participate in multi-state plans that 

address the affected EGUs owned and operated by a utility with a 

multi-state service territory. 

6. Legal bases for state plan types and approaches [note, legal 

discussions consolidated into one section, see below] 
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a. Legal basis for emission standards approach. The emission 

standards approach is consistent with the requirements of CAA 

section 111(d). If a state simply adopts the CO2 emission 

performance rates, then the corresponding rate-based emission 

standards in the state plan establish standards of performance 

for affected EGUs as required under section 111(d)(1)(A). 

Similarly, if a state chooses to achieve the rate-based CO2

emission goal through rate-based emission standards, or to 

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 
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performance. 

b. Legal basis for emissions trading in state plans. There are 

three legal considerations with respect to emissions trading in 

state plans. First, we explain how the definition of “standard 

of performance” in section 111(a)(1) allows section 111(d) plans 

to include standards of performance that authorize emissions 

trading. Second, we explain how the EPA interprets the phrase 

“provides for implementation and enforcement of [the] standards 

of performance” in the context of a rate-based ERC trading 

program. Third, we give a similar explanation of the EPA’s 

interpretation of the same phrase in the context of a mass-based 

allowance trading program. 

(1) In the proposal, the EPA proposed that CAA section 111(d) 

plans may include standards of performance that authorize 

emissions averaging and trading. 79 FR 34830, 34927/1 (June 18, 

2014). We are finalizing that states may include the use of 

emission trading in approvable state plans. 

For purposes of this legal discussion, in the case of an 

emission limitation expressed as an emission rate, trading takes 

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 
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as a mass-based limit, trading takes the form of buying or 

selling allowances. 

To reiterate for convenience, the definition of “standard 

of performance” under CAA section 111(a)(1) is: 

The term ‘standard of performance’ means a standard 

for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the 

application of the best system of emission reduction 

which (taking into account the cost of achieving such 

reduction and any nonair quality health and 

environmental impact and energy requirements) the 

Administrator determines has been adequately 

demonstrated. 

Both an emission rate that may be met through tradable 

ERCs, and a 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,683

which, under either a Chevron step 1 or step 2 analysis, would 

include an emission rate that may be met through tradable ERCs 

 

683 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). 
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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.”684 In addition, in the 1995 Municipal 

Solid Waste (MSW) Combustor rule the EPA authorized emission 

trading by sources.685

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 

 

684 70 FR 28606, 28616-17 (May 18, 2005). 685 60 FR 65387, 6540/2 (Dec. 19, 1995).
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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 

tradable emission rate or allowance program is appropriate for 

CO2 emissions, the air pollutant covered by this rule, because 

the environmental effects of CO2 emissions are not dependent on 

the location of the emissions. 

(2) In our final rule, we are prescribing certain specific 

requirements for trading systems for ERCs in a rate-based 

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 
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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 federally 

enforceable requirements under a CAA section 111(d) state plan 

can be imposed on entities other than affected EGUs. It is 

important to note that the use of ERCs 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 of such compliance 

units. In the Legal Memorandum we also discuss specific legal 

considerations regarding EM&V requirements, 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 
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below for the legal basis for the generic requirements for state 

plans) and are intended to ensure the integrity of the allowance 

trading system. The integrity of the trading system is key to 

ensuring that a state plan provides for implementation and 

enforcement of the standards of performance. 

Our interpretation of the phrase “provides for 

implementation and enforcement of [the] standards of 

performance” in the context of the integrity of a trading system 

for allowances under a mass-based approach is further explained 

in the Legal Memorandum. 

c. Legal basis for state measures plan type. The EPA believes 

the state measures plan type is consistent with CAA section 

111(d). Section 111(d)(1) requires a state to submit a plan that 

“(A) establishes standards of performance for any existing 

source for [certain] air pollutant[s] ... and (B) provides for 

the implementation and enforcement of such standards of 

performance.” Section 111(d)(2)(A) indicates that the EPA must 

approve the state plan if it is “satisfactory.” 

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 requires a state to 
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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. A key condition is that the state plan provides for 

the achievement of the required reduction by means other than 

the standards of performance on the timetable required by BSER, 

with provision for federally enforceable standards of 

performance to be implemented if those other means fall short. 

The Legal Memorandum discusses in more detail why the EPA 

believes it is reasonable to defer the effective date for 
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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)(1)(B) also requires a state to submit a 

program that provides for the implementation and enforcement of 

the applicable standards of performance. Under the state 

measures approach, this requirement regarding implementation is 

satisfied by the submission of an approvable trigger mechanism 

for the backstop and appropriate monitoring, reporting and 

recordkeeping requirements. The trigger mechanism provides for 

the “implementation” of the backstop, i.e. the standards of 

performance, by putting the backstop into effect once the 

associated trigger is deployed. In other words, when the CO2

performance level under a state plan exceeds the trigger as 

described in section VIII.C.4.b, the emission standards that 

were submitted as the federally enforceable backstop and any 

attendant requirements must be implemented and in effect. The 

statutory requirement under CAA section 111(d)(2) regarding 

enforcement is also satisfied under the state measures plan type 

by the state submitting standards of performance sufficient to 

meet the requisite emission performance rates or state goal, in 

the form of the backstop, for inclusion as part of the federally 
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enforceable state plan. 

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 is also a variation of the proposed state 

commitment approach in that the measures involving entities 

other than affected EGUs are not included as part of the 

federally enforceable 111(d) state plan, but the state may rely 

upon such measures that have the effect of reducing CO2 emissions 

from affected EGUs as a matter of state law. The EPA took 

comment on the proposed portfolio approach and state commitment 

approach, and on the utilization of measures on entities other 

than affected EGUs in meeting the requirements of the emission 

guidelines and CAA section 111(d). With respect to the proposed 

state commitment approach, the EPA received comments 

recommending that the EPA require a federally enforceable 

backstop with emission standards sufficient to achieve the 

requisite CO2 emission performance. The backstop component the 

EPA is finalizing as part of the state measures plan type is 

consistent with the EPA’s statements in the proposal regarding 
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states’ obligations under section 111(d) to establish emission 

standards for affected EGUs, as the backstop contains federally 

enforceable emission standards for affected EGUs that will 

achieve the requisite CO2 emission performance, and is 

consistent with comments received regarding the proposed state 

commitment approach. 

The state measures plan type the EPA is finalizing is also 

a logical outgrowth of the comments received on the proposed 

portfolio approach. As further explained below, legal questions 

remain as to whether state plans under section 111(d) can 

include federally enforceable measures that impose requirements 

on sources other than affected EGUs. However, a number of 

commenters and stakeholders expressed robust support for the 

ability to rely on measures and programs that do not impose 

requirements on affected EGUs themselves through plan types such 

as the proposed portfolio and state commitment approaches. The 

EPA is reasonably interpreting 111(d) as authorizing the state 

measures plan type, and believes this plan type is also 

responsive to, and accommodating of, states and stakeholders who 

have expressed the importance of being able to rely upon various 

measures that have the effect of resulting in CO2 reductions from 

affected EGUs. The EPA is finalizing the state measures plan 
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type upon careful consideration of statutory requirements and 

comments received based on the proposed portfolio approach and 

state commitment approach. 

The EPA additionally notes a legal consideration with 

respect to the state measures plan type it is finalizing. 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 

(“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 
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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 

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 
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addition, case law suggests that federal enforceability for 

every requirement may not be necessary when there are sufficient 

federally enforceable requirements to satisfy the statute, see 

National Mining Ass'n v. United States EPA, 59 F.3d 1351 (D.C. 

Cir. 1995); in this case federal enforceability for the stateonly measures is not necessary to meet the statutory 

requirements of section 111(d)(1) as the federally enforceable 

trigger and backstop are sufficient. 

d. Legal 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 

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 
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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”). 

e. Legal basis for 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 
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proposed the following as necessary components of an approvable 

state plan: 

1. The plan must contain enforceable measures that reduce 

EGU CO2 emissions; 

2. The enforceable measures must be projected to 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 
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“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 

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.686 

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, 

 

686 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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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. 

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
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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 

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 
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to the EPA’s decision to finalize the option for states to 

submit a state measures plan, which would be comprised, at least 

in part, of measures implemented by the state that are not 

included as federally enforceable components of the plan, with a 

backstop of federally enforceable emission standards for 

affected EGUs that fully meet the emission guidelines and that 

would be triggered if the plan failed to achieve the CO2 emission 

performance levels specified in the plan on schedule. For more 

information on the state measures plan approach, see section 

VIII.C.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 
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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. A states pursuing the emission standards 

approach plan type may also opt to submit a plan that meets the 

CO2 emission performance rates for affected EGUs or meets the 

state rate-based or mass-based CO2 emission goal. A state 

implementing a state measures approach plan type must submit a 

plan that meets the state mass-based CO2 goal. The content 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 multi-state 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 
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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 

applicable to each component in the plan submittal. 

(2) 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. 

(3) Demonstration that a state plan will achieve the CO2 emission 

Deleted: .(
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performance rates or state CO2 goal. A state plan submittal must 

demonstrate that the federally enforceable emission standards on 

affected EGUs and/or state measures are sufficient to meet 

either the CO2 emission performance rates or the state’s CO2

emission goal in the emission guidelines for the interim and 

final plan performance periods. This includes during the interim 

period of 2022-2029, including the interim step 1 period (2022-

2024); interim step 2 period (2025-2027); and interim step 3 

period (2028-2029) period, as well as during the final period of 

2030-2031 and subsequent 2-year periods.687 CO2 emission 

performance projections are required through 2031. For the post2031 period, the demonstration requirement may be satisfied by 

showing that emissions standards or state measures on which the 

projection is based are permanent and will remain in place. As 

discussed in more detail in section VIII.K, states adopting a 

plan based upon a mass-based statewide CO2 emission goal must 

 

687 State plans may meet the CO2 emission performance rates in the 

emission guidelines during the interim plan performance step 

periods, or assign different interim step CO2 emission 

performance rates, provided the CO2 emission performance rates in 

the emission guidelines are achieved during the full interim 

period. Likewise, a state plan may meet the interim step state 

mass-based CO2 goals in the emission guidelines or establish 

different interim step mass-based CO2 emission levels, provided 

the state interim mass-based CO2 goal is achieved during the full 

interim period. 
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demonstrate that they have addressed the risk of leakage in 

their mass-based state plan and show that there is equivalency 

with a rate-based approach. 

The type of demonstration and documentation required for a 

state plan will vary depending on how the CO2 emission standards 

for affected EGUs and/or state measures in a state plan are 

applied across the fleet of affected EGUs in a state, as 

discussed below.688 

(a) Plan design instances that require a projection. Whether a 

projection of affected EGU CO2 emission performance must be 

included in a state plan submittal depends on the design of the 

state plan. The following plan designs do not require a 

projection of CO2 emission performance by affected EGUs under the 

state plan because they ensure that the CO2 emission performance 

rates or a state rate-based or mass-based CO2 goal is achieved 

when affected EGUs comply with the emission standards. 

 

688 For simplicity purposes, the EPA refers here to state 

measures under a state measures plan as being included “in the 

state plan” although such state-enforceable measures are not 

codified as part of the federally enforceable approved state 

plan. However, the approval of a state measures plan is 

dependent on a demonstration in the state plan submittal that 

those state-enforceable measures meet the requirements in the 

emission guidelines and that those state measures, alone or in 

combination with federally enforceable emission standards for 

affected EGUs, will meet the mass-based CO2 goal. 
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 State plan establishes separate rate-based CO2 emission 

standards for affected fossil fuel-fired electric utility 

steam generating units and stationary combustion turbines 

(in lb CO2/MWh) that are equal to or lower than the CO2

emission performance rates in the emission guidelines. 

 State plan establishes a single rate-based CO2 emission 

standard for all affected EGUs that is equal to or lower 

than the state’s rate-based CO2 goal in the emission 

guidelines. 

 State plan establishes mass-based emission standards for 

affected EGUs that result in mass emission limits for 

affected EGUs that cumulatively do not exceed a state’s 

mass-based state CO2 goal in the emission guidelines 

during the interim and final plan performance periods. If 

the plan includes a mass-based emission trading program, 

the plan establishes emission budgets during the interim 

and final plan performance periods that are equal to or 

less than the state’s mass-based CO2 goal for the interim 

and final plan performance periods. 

All other state plan designs must include a projection of 

CO2 emission performance by affected EGUs under the state plan. 

For example, if a state chooses to apply rate-based CO2 emission 
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standards to individual affected EGUs, or to sub-categories 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 (e.g., higher than) the CO2

emission performance rates or the state’s rate-based CO2 goal in 

the emission guidelines, then a projection is required. 

Likewise, if a state chooses a state measures state plan 

approach, a projection of CO2 emission performance is required. 

Any state plan that requires a CO2 emission performance 

projection must document the following: 

• An explanation of the methods and tools used in the 

projection. 

• Underlying assumptions used in the projection as 

described below and specified in the State Plan Technical 

Support Document (State Plan TSD).

• CO2 performance projection that includes all applicable 

emission standards applied to affected EGUs and/or state 

measures in the state plan, as described below and 

specified in the State Plans TSD. 

(b) Methods and tools. A satisfactory demonstration of the 

future CO2 performance of affected EGUs must use technically 

sound methods that are reliable and replicable. A state plan 
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submittal must explain how the projection method and/or tool 

works and why the method and/or tool chosen is appropriate 

considering the type of emission standards and/or state measures 

included in a state plan. The results in the demonstration must 

be reproducible using the documented assumptions described in 

the state plan submittal. The method and projection of EGU 

dispatch and CO2 emissions can differ from the EPA’s forecast in 

the RIA. 

The EPA received comments on whether it would require 

specific modeling tools and input assumptions. Commenters raised 

concerns that the EPA may require states to use proprietary 

models, and that states do not have the financial resources to 

use such models. The EPA is not requiring a specific type of 

method or model, as long as the one chosen uses technically 

sound methods and tools that establish a clear relationship 

between electricity grid interactions and the range of factors 

that impact future EGU generation, dispatch, and CO2 emissions. 

Methods and tools could range from applying future growth rates 

to historical generation and emissions data, or using 

statistical analysis, to electric sector energy modeling. 

(c) Required documentation of projection assumptions. When 

required, a CO2 emission performance projection must document all 
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input assumptions and projection outputs. Comprehensive 

documentation is necessary in order for the EPA to assess the 

reasonableness of the projection. At a minimum, states must 

document the following input assumptions and projection outputs 

in their state plan: 

(i) Key analytic assumptions. 

 Time period of analysis; must extend through 2031 

 Electricity demand forecast (MWh load and MW peak demand) 

at the state and regional level. 

 If the demand forecast is not from NERC, an ISO or 

RTO, EIA, or other publicly available source, then the 

projection must include justification and 

documentation of underlying assumptions that inform 

the development of the demand forecast such as annual 

economic and demand growth rate, population growth 

rate. 

 EGU fleet-wide assumptions 

 Planning reserve margin 

 Planned new generation 

 Fuel prices, when applicable; 

 Fixed operations and maintenance costs, when 

applicable; 
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 Variable operations and maintenance costs, when 

applicable; 

 Affected EGU-specific assumptions: 

 Generation capacity, capacity factors and heat rates 

(ii) Key state plan requirements/measures scenario inputs. 

 Federally enforceable emissions standards for each 

affected EGU, as applicable; 

 EGU-specific actions to meet standards, including 

retirements, heat rate improvements and fuel 

switching; expected electricity generation and CO2 

emission-related impacts of actions; timeline for 

implementation 

 State-enforceable measures with electricity savings and 

renewable electricity generation (MWhs) expected for 

individual and collective measures; 

 Quantification of MWhs expected from energy efficiency 

and renewable energy measures will involve assumptions 

that states must document, as described in the State 

Plan TSD. Specific documentation requirements for 

emission rate credit or emission budget trading 

programs are also described in the State Plan TSD. 

 Note: If a plan includes both federally and state-
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enforceable measures, projection should account for 

the interaction between actions. 

(iii) Outputs. 

 Annual electricity generation (MWhs) by fuel type and CO2 

emission levels, for each affected EGU 

 Emission rate credit (ERC) or emission allowance prices, 

when applicable 

 Wholesale electricity prices, when available 

(iv) Post-2030 demonstration: 

 Affirmation that measures and/or requirements used to 

demonstrate projected achievement of the final goal by 

2030 will be permanent and remain in place. 

Because electricity flows across state boundaries, singlestate plan demonstrations must consider regional interactions 

when projecting CO2 performance. Multi-state plans or plans 

linking common elements should use regional assumptions or 

demonstrate reconciliation of any inconsistencies between statelevel assumptions and regional assumptions. For additional 

details regarding the specific elements that must be documented 

in a projection of CO2 emission performance, see the State Plan 

TSD. 

(d) Additional projection requirements under a rate based 
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emissions standards plan. For an emission standards plan that 

applies rate-based CO2 emission standards to individual affected 

EGUs, or to sub-categories of affected EGUs, at a lb CO2/MWh rate 

that differs from (e.g., higher than) the CO2 emission 

performance rates or the state’s rate-based CO2 goal in the 

emission guidelines, a projection of affected EGU CO2 emission 

performance is required. The state must demonstrate that the 

weighted average CO2 emission rate of affected EGUs, when 

weighted by generation (in MWh) from affected EGUs subject to 

the different rate-based emission standards, will be equal to or 

less than the CO2 emission performance rates or the state's ratebased CO2 emission goal during the interim and final periods. 

The projection will involve an analysis of the change in 

dispatch of affected EGUs given the compliance costs and 

incentives under the application of different emission rate 

standards across affected EGUs in a state. It must accurately 

represent the emission standards in the plan and the use of ERCs 

for compliance, including market-based aspects of the emission 

standards, if relevant. 

In addition to the elements described in the previous 

section (c), the projection under this plan design must include: 

• The assignment of federally enforceable emissions 
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standards for each affected EGU; 

• A projection showing how dispatch is expected to shift 

between and across affected EGUs over time; 

• The specific calculation of how eligible MWh of 

electricity generation or savings (or ERCs) are being 

used in the projection to adjust the CO2 emission rate of 

affected EGUs, consistent with the accounting methods for 

adjusting the CO2 emission rate of an affected EGU 

specified in section VIII.K.1.(a)of the emission 

guidelines, if applicable; 

• ERC prices, if applicable; 

• If certain resources that will provide MWh generation (or 

ERCs) to adjust the reported CO2 emission rates of 

affected EGUs are or will be located in a state with a 

mass-based plan, demonstration that the resources are or 

will be eligible, based on Power Purchase Agreements 

(PPAs) , Renewable Energy Certificates (RECs) or related 

documentation, consistent with the requirements at 

Section VII.K.2. of the final preamble. 

• Any other applicable assumptions used in the projection. 

For additional details regarding the specific elements that 

must be documented in a projection of CO2 emission performance, 
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see the State Plan TSD. 

(e) Additional projections requirements for a state measures 

plan. For a state measures plan, a projection of affected EGU CO2

emission performance must demonstrate that the state measures, 

whether alone or in conjunction with any federally enforceable 

CO2 emission standards, will achieve the mass-based CO2 goals in 

the emission guidelines for the interim and final periods. The 

projection must accurately represent individual stateenforceable measures (or bundled measures) and timing for 

implementation of these state measures. 

(1) Projections for a rate-based state measures plan. In 

addition to the elements described in section (c), this 

projection must include the following key information, at a 

minimum, to demonstrate the rate-based state measures plan will 

achieve the mass-based CO2 goals in the emission guidelines for 

the interim and final periods: 689 

 The assignment of federally enforceable emissions 

 

689 If a state is implementing a rate-based state measures plan, 

this demonstration would be based on projected CO2 mass emissions 

from affected EGUs. In its state plan submittal, however, a 

state could propose, for EPA consideration, a method to adjust 

the projected mass CO2 emissions from affected EGUs to account 

for zero emission MWh of electricity savings and renewable 

electricity generation or ERCs when demonstrating that a plan 

will achieve the state mass-based CO2 goal. 
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standards by affected EGU, if applicable; 

 Description of the state measures; 

 Projection of MWh of electricity savings and renewable 

electricity generation and that will occur during the 

interim and final plan performance periods as a result of 

the state measures. The projection must document the 

assumptions used to quantify the MWh impacts of energy 

efficiency and renewable energy-related measures, 

including but not limited to the technology-type (e.g., 

wind, solar, demand-side EE) and the physical location of 

the eligible resources, as described in the State Plan 

Technical Support Document. 

 Documentation of the anticipated use of ERCs. 

 An explanation, with calculation, of how eligible MWh of 

electricity generation or savings are being used in the 

projection to adjust the CO2 emission rate of affected 

EGUs; 

 A calculation of how the affected EGU rates are converted 

to mass-based CO2 state goals 

 If certain resources that will provide MWh generation 

used to adjust the reported CO2 emission rates of 

affected EGUs are or will be located in a state with a 
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mass-based plan, demonstration that the resources are or 

will be eligible, based on power purchase agreements 

(PPAs), renewable energy certificates or other related 

documentation, consistent with the requirements at 

section VIII.K.2 of the final preamble. 

 Any other applicable assumptions used in the projection. 

Consistent with the requirements specified in section 

VIII.K.1.(a) of the final preamble, the projection must show 

both the calculation of the mass-based CO2 state goals and any 

applicable rate adjustment of the projected CO2 emission rates of 

affected EGUs due to the MWhs of electricity savings or 

renewable energy generation expected as a result of the stateenforceable measures in a state plan. Additional details 

regarding the specific elements that must be documented in a 

projection of CO2 emission performance, see the State Plan TSD. 

(2) Projections for a mass-based state measures plan. Under a 

mass-based state measures plan, a state must demonstrate that 

its state-enforceable measures, along with any federally 

enforceable CO2 emission standards for affected EGUs included in 

a state plan, will achieve the state mass-based CO2 goal. As 

such, in addition to the elements described in Section (c), the 

state must clearly document, at a minimum: 
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• the assignment of federally enforceable emissions 

standards for each affected EGUs, if applicable; 

• the individual state measures, including their 

projected impacts over time. 

 Because different types of state measures could have 

varying degrees of impact on reducing or avoiding CO2 emissions 

from affected EGUs, and different state measures may interact 

with one another in terms of CO2 emission reduction impacts, the 

method and tools a state uses to project CO2 emissions impacts 

must have the capability to project how the combined set of 

state-enforceable measures are likely to impact CO2 emissions at 

affected EGUs. If a state chooses to use an emission budget 

trading program as a mass-based state measure, for example, the 

state must choose an analytic method or tool that can account 

for and properly represent any program flexibilities, including 

multiyear compliance periods, banking of allowances, use of outof-sector project-based emission offsets and cost-containment 

allowance reserves. For example, a mass-based state measures 

plan that incorporates an emissions budget trading program that 

includes a broader set of emission sources, such as programs 

implemented by California and the RGGI participating states, 

would fall under the state measures state plan approach. The 
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state would show that the state enforceable emissions budget 

trading program and state measures ensure that the sum of 

emissions at all affected EGUs will be lower than or equal to 

the state’s CO2 emission goal in the time periods specified in 

these guidelines. All flexibilities must be clearly documented 

in the demonstration. For additional details regarding the 

specific elements that must be documented in a projection of CO2 

emission performance, see the State Plan TSD. 

(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 

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 
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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. 

The EPA requested comments on the whether full reports 

containing all of the report elements should only be required 

every two years and on the appropriate frequency of reporting of 
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the different proposed elements, considering both the goals of 

minimizing unnecessary burdens on states and ensuring program 

effectiveness. Commenters recognized that different reporting 

frequencies may be appropriate for different type of state 

plans. The EPA agrees with the commenters and is finalizing 

state reporting requirements based on the type of plan approach 

the state chooses to adopt and implement. These state reporting 

requirements and reporting periods are discussed in section 

VIII.D.2.b (for emission standards approach) and VIII.D.2.c (for 

state measures approach). The EPA finalizes that each state 

report is due to the EPA no later than the July 1 following the 

end of each reporting period. The EPA recognizes the multiple 

comments received recommending extending the state report due 

date from July 1 to a later date or to allow the states the 

flexibility to propose an alternative report submittal date. The 

EPA is not pursuing these recommendations due to the 

implications of the state reports due date and the trigger and 

schedule for implementation of corrective measures (for the 

emission standards approach) or the backstop (for the state 

measures approach). 

In addition to the state reporting requirements discussed 

in section VIII.D.2.b (for emission standards approach) and 
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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 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, which would then trigger, 

per the requirements of CAA section 111(d), the EPA’s obligation 

to develop and implement a federal plan in the instance of such 

disapproval. 

The EPA is finalizing the requirement that submissions 

related to this program be submitted electronically. 
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Specifically, that includes negative declarations, state plan 

submittals (including any supporting materials that are part of 

a state plan submittal), any plan revisions, and all reports 

required by the state plan. The 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 

requirements due to the burden in expenditure of resources and 

manpower to maintain records for at least 20 years. Commenters 

recommended that recordkeeping requirements be reduced to 5 

years consistent with emission guidelines for other existing 

sources. 

After considering the comments received, this final rule 

requires that a state must keep records of all plan components, 
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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 

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 
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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) Public participation and certification of hearing on state 

plan. For the final plan submittal, states must meaningfully 

engage with members of the public, including overburdened 

communities, during the plan development process. The existing 

implementing regulations regarding public participation 

requirements are in 40 CFR 60.23(c)-(f). Per the implementing 

regulations, states must conduct a public hearing on a final 

state plan before such plan is adopted and submitted. The EPA 

also encourages states to conduct outreach meetings (that could 

include public hearings or meetings) with overburdened 

communities on its initial plan before the plan is submitted. In 

its plan submittal, a state must provide certification that the 

state made the plan submittal available to the public and gave 

reasonable notice and opportunity for public comment on the 

state plan submittal. The state must demonstrate that the public 
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hearing on the state plan was held only after reasonable notice, 

which will be considered to include, at least 30 days prior to 

the date of such hearing, notice given to the public by 

prominent advertisement announcing the date(s), time(s) and 

place(s) of such hearing(s). For each hearing held, a state plan 

submittal must include in the supporting documentation the list 

of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

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). The EPA also encourages states to provide 

background information about their proposed final state plan or 

their initial state plan in the appropriate languages in advance 

of their public hearing and at their public hearing. 

Additionally, the EPA recommends that states provide translators 

and other resources at their public hearings, to ensure that 

members of the public can provide oral feedback. 

As previously discussed in this rule, recent studies also 

find that certain communities, including low-income communities 

and some communities of color (more specifically, populations 
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defined jointly by ethnic/racial characteristics and geographic 

location) are disproportionately affected by certain climate 

change related impacts690. Also as discussed in this rule, 

effects from this rule can be anticipated to impact communities 

in various ways. Because certain communities have a potential 

likelihood to be impacted by state plans, the EPA believes that 

the existing public participation requirements under 40 CFR 

60.23 are effectuated for the purposes of this final rule by 

states engaging in meaningful, active ways with such 

communities. 

In addition certain communities whose economies are largely 

based on coal may be particularly impacted by the final rule. 

The EPA also encourages states to make an effort to provide 

background information about their proposed final state plan or 

their initial state plan to these communities in advance of 

their public hearing. 

The EPA notes that meaningful public involvement goes beyond 

the holding of a public hearing. The EPA envisions meaningful 

engagement to include outreach to overburdened communities, 

 

690 USGCRP 2014: Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global 

Change Research Program, 841 pp. 
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sharing information and soliciting input on state plan 

development and on any accompanying assessments, such as those 

described in section IX. In section VIII.E, the EPA provides 

states with examples of resources on how they can engage with 

overburdened 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, labor unions, and others 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 overburdened 

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 
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(regulations/legislation) and funding to implement and enforce 

each component of the state plan submittal, including federally 

enforceable emission standards for affected EGUs and state 

measures. A state can make such a demonstration by providing 

supporting material related to the state’s legal authority used 

to implement and enforce each component of the plan, such as 

copies of statutes, regulations, PUC orders, and any other 

applicable legal instruments. For states participating in a 

multi-state plan, the submittal(s) must also include as 

supporting documentation each state’s necessary legal authority 

to implement the portion of the plan that applies within the 

particular state, such as copies of state regulations and 

statutes, including a showing that the states have the necessary 

authority to enter into a multi-state agreement. 

(b) Technical documentation. As applicable, the state submittal 

must include materials necessary to support the EPA’s evaluation 

of the submittal including analytical materials used in the 

calculation of interim goal steps, 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 
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proposes to use to implement elements of the plan. 

(c) Programmatic milestones and timeline. As part of the state 

plan supporting documentation, the state must include in its 

submittal a timeline with all the programmatic milestone steps 

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

and 2022 to ensure the plan is effective as of 2022. The 

programmatic milestones and timeline should be appropriate to 

the overall state plan approach included in the state plan 

submittal. 

(d) Reliability. As discussed in more detail 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 

the preceding section VIII.D.2.a. 

(1) Identification of interim period emission performance rates 

or state goal (for 2022-2029), interim step performance rates or 

interim state goals (2022-2024; 2025-2027; 2028-2029) and final 

emission performance rates or state goal (2030 and beyond). The 

state plan submittal must indicate whether the plan is designed 
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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. 

 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-
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2029.691 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 

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 

 

691 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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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 

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 
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mass-based goals of the participating states, in tons of CO2. The 

plan submittal must include in its supporting documentation a 

description of the analytic process, tools, methods, and 

assumptions used to calculate the joint multi-state goal. 

(2) Identification of federally enforceable emission standards 

for affected EGUs. The state plan submittal 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 

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 2 calendar years. States can choose to set 

shorter compliance periods for the emission standards than the 

compliance periods the EPA is finalizing in this rulemaking, but 

cannot set longer periods. As discussed in more detail in 

section VIII.F, the EPA recognizes that the compliance periods 
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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 

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 
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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 

affected EGUs to demonstrate compliance (allowance “true-up” 

with reported CO2 emissions.) 

(3) Demonstration that each emission standard is quantifiable, 

non-duplicative, permanent, verifiable and enforceable. The plan 

submittal must demonstrate that each emission standard is 

quantifiable, non-duplicative, permanent, verifiable and 

enforceable with respect to an affected EGU, as outlined below. 
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An emission standard is quantifiable if it can be reliably 

measured, using technically sound methods, in a manner that can 

be replicated.692 

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 

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.693 This does not mean that 

 

692 The CO2 continuous emissions monitoring system (CEMS) is the 

most technically reliable method of emission measurement for 

EGUs. CEMS provide a measurement method that is performance 

based rather than equipment specific and 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. 

693 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 
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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, 

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 

 

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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responsible for compliance and liable for violations can be 

identified, (4) each compliance activity or measure is 

enforceable as a practical matter in accordance with EPA 

guidance on practical enforceability,694 and the Administrator, 

the state, and third parties, maintain the ability to enforce 

against violations and secure appropriate corrective actions, in 

the case of the Administrator pursuant to CAA sections 113(a)–

(h), in the case of a state, pursuant to its plan, state law or 

CAA section 304, as applicable, and in the case of third 

parties, pursuant to CAA section 304. 

In developing its CAA section 111(d) plan, to ensure that 

the plan submittal is enforceable and in conformance with the 

CAA, a state should follow the EPA’s prior guidance on 

enforceability.695 These guidance documents serve as the 

foundation for the types of monitoring, reporting, and emission 

standards that the EPA has found can be, as a practical matter, 

 

694 See prior footnote. 695 The EPA guidance on enforceability includes: (1) September 

23, 1987, memorandum and accompanying implementing guidance, 

“Review of State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,” (2) August 5, 2004, 

“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures,” and (3) 

July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable 

Energy Policies and Programs into State and Tribal 

Implementation Plans, Appendix F.” 
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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” TSD696 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, 

comments received, and the clear statutory foundation. 

 (4) State reporting requirements. After consideration of the 

 

696 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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comments received regarding state reporting requirements, the 

EPA is finalizing for state plans using the emission standards 

approach that a state report is due to the EPA no later than the 

July 1 following the end of each reporting period. For the 

interim period (2022-2029) the EPA is finalizing the following 

interim reporting periods: interim step 1 covers the 3 calendar 

years 2022-2024; interim step 2 covers the 3 calendar years 

2025-2027 and interim step 3 covers the 2 calendar years 2028-

2029. A biannual state report is required starting in 2030 and 

beyond covering the 2 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 and is responsive of comments received that 

different reporting frequencies may be appropriate for different 

type of state plans. The EPA believe states implementing the 

emission standard approach merits this reporting frequency due 

to the federally enforceable emission standards that apply to 

affected EGUs and their corresponding monitoring, reporting and 

recordkeeping requirements. 

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
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emission performance by affected EGUs during the reporting 

period. The state report must include compliance demonstrations 

for affected EGUs and identify whether affected EGUs are on 

schedule to meet the applicable CO2 emission performance rate or 

emission goal during the performance periods and compliance 

periods, as specified in the state plan. For rate-based emission 

trading programs, the report must also include for EPA review 

the state’s review of the administration of their state ratebased emission trading program, as discussed in section 

VIII.K.2.g. 

As discussed in more detail in section VIII.F, in each 

report during the interim period (2022-2029), the state must 

include an interim performance check. The interim performance 

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 
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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 interim state mass goal (for 2022-2029), 

interim step state mass goals (2022-2024; 2025-2027; 2028-2029) 

and final state mass goal (2030 and beyond). The state plan 

submittal must identify the mass-based CO2 emission goal that 

must be achieved through the plan (expressed in tons of CO2). The 

plan submittal must identify the state CO2 interim period goal 

(for 2022-2029), interim 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. 

 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 
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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-

2029.697 States are free to establish different interim step 

goals than those the EPA has specified in this final rule. If 

states choose to determine their own interim step goals, the 

state must demonstrate that it will still meet the interim goal 

for 2022-2029 finalized in this action and the plan submittal 

must include in its supporting documentation a description of 

the analytic process, tools, methods, and assumptions used to 

make this demonstration. 

For states participating in a multi-state plan with a joint 

goal (for interim and final periods), the individual state goals 

in the emission guidelines would be replaced with an equivalent 

multi-state goal for each period (interim and final). The joint 

goal would be a sum of the individual mass-based goals of the 

participating states, in tons of CO2. The plan submittal must 

include in its supporting documentation a description of the 

analytic process, tools, methods, and assumptions used to 

calculate the joint multi-state goal. 

 

697 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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(2) Identification of federally enforceable emission standards 

for affected EGUs (if applicable). If applicable, the state plan 

submittal must include any federally enforceable CO2 emission 

standards that apply to affected EGUs, and demonstrate that 

those emission standards meet the requirements that apply in the 

context of an emission standards approach, discussed in the 

preceding section VIII.D.2.b. Specifically, the state plan 

submittal must demonstrate that each federally enforceable 

emission standard is quantifiable, non-duplicative, permanent 

and verifiable. 

(3) Identification of backstop of federally enforceable emission 

standards. A state measures plan must include a backstop of 

federally enforceable emission standards for affected EGUs that 

fully achieve the 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 
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standards approach, discussed in the preceding section, identify 

a schedule and trigger for implementation of the backstop that 

is consistent with the requirements in the emission guidelines 

as discussed in section VIII.C.4.b and identify all necessary 

state administrative and technical procedures for implementing 

the backstop (e.g. how and when the state would notify affected 

EGUs that the backstop has been triggered). Aspects of the 

backstop are discussed in detail in section VIII.C.4.b. 

(4) 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. 

 (5) State reporting requirements. After consideration of the 
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comments received regarding state reporting requirements, the 

EPA is requiring in this final rule for states using the state 

measures approach that an annual state report is due to the EPA 

no later than July 1 following the end of each calendar year 

during the interim period. This annual state report must include 

the status of implementation of federally enforceable emission 

standards (if applicable) and state measures and 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. For ratebased emission trading programs, the report must also include 

for EPA review the state’s review of the administration of their 

state rate-based emission trading program, as discussed in 

section VIII.K.2.g. The EPA believes that annual state reporting 

is appropriate for state measures approach due to the 

flexibility inherent to the approach described in section 

VIII.C.4. 

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. 
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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 

has not met 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 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 
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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. 

(6) 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 

submittal the state measures698 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. 

 

698 “State measures” refer to measures that the state adopts and 

implements as a matter of state law. Such measures are 

enforceable only per applicable state law, and are not included 

in the federally enforceable state plan. 
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A state measure is 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 

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. 
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A state measure is enforceable699 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,700 and the state maintains the ability 

to enforce against violations and secure appropriate corrective 

actions pursuant to its plan or state law. 

The EPA will disapprove a state plan if the documentation 

is not sufficient for the EPA to be able to determine whether 

the state measures are expected to yield CO2 emission reductions 

sufficient to result in the necessary CO2 emission performance 

 

699 Under the state measures approach, state measures are 

enforceable only per applicable state law. 

700 The EPA’s prior guidance on enforceability serves as the 

foundation for the types of measures that the EPA has found can 

be, as a practical matter, enforced. The EPA’s guidance on 

enforceability includes: (1) September 23, 1987, memorandum and 

accompanying implementing guidance, “Review of State 

Implementation Plans and Revisions for Enforceability and Legal 

Sufficiency,” (2) August 5, 2004, “Guidance on SIP Credits for 

Emission Reductions from Electric-Sector Energy Efficiency and 

Renewable Energy Measures,” and (3) July 2012 “Roadmap for 

Incorporating Energy Efficiency/Renewable Energy Policies and 

Programs into State and Tribal Implementation Plans,” Appendix 

F. 
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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 

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 
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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 

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 
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fundamental nature in the section 110 context.701 

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 

“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 

 

701 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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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 

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 
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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 considerations 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 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) 
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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 

standards of performance in 111(d) plans on existing sources “to 

which a standard of performance under [111] would apply if such 
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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 

corresponding section 111(b) standards of performance for the 
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same pollutant, that the emission guidelines cannot identify (b) 

sources as affected sources and require state plans to 

promulgate standards for those sources. 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 

unfair surprise that sections 111(a)(2) and 111(a)(6) formed the 

Deleted: 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.

Commented [A21]: As worded, I believe this sentence could be 

read to preclude states from opting in new plants in their mass-based 

plans 
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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 considerations 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.702 

 

702 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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This follows from the statute. First, section 111(h)(1) 

authorizes the Administrator, when it is not feasible for 

certain reasons (specified in 111(h)(2)) to prescribe or enforce 

a standard of performance, to instead promulgate a design, 

equipment, work practice or operational standard. If a standard 

of performance could include design, equipment, work practice or 

operational standards, such authority would be unnecessary. 

Second, 111(h)(5) states that design, equipment, work practice 

or operational standards “described in” 111(h) shall be treated 

as standards of performance for the purposes of the CAA. This 

creates a strong inference that standards of performance 

otherwise should not include design, equipment, work practice, 

or operational standards. Finally, the general definition of 

“standard of performance” in 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 
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practice, and operational standards in 302(l) confirms our 

interpretation that they cannot be a 111 “standard of 

performance” (except under the limited circumstances in 111(h)). 

We conclude that it is reasonable, and perhaps compelled, to 

interpret the term “standards of performance” in 111(d) to not 

include design, equipment, work practice and operational 

standards. 

However, section 111(d) requires plans to “provide for 

implementation and enforcement of [the] standards of 

performance.” This language does not explicitly prohibit a plan 

from including design, equipment, work practice and operational 

standards, and allows for them to be included so long as they 

are understood to provide for implementation of the standards of 

performance. If they are included, the 111(d) plan must still be 

“satisfactory” in other respects, in particular in establishing 

standards of performance that are not in whole or in part 

design, equipment, work practice, and operational standards. 

(4) Legal basis for engagement with communities. As previously 

discussed, section 111(d)(1) requires the EPA to promulgate 

procedures “similar” to those in section 110 under which states 

adopt and submit 111(d) plans. Section 110(a)(1) requires states 

to adopt and submit implementation plans “after reasonable 
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notice and public hearings.” The implementing regulations under 

40 CFR 60.27 reflect similar public participation requirements 

with respect to section 111(d) state plans. The EPA is sensitive 

to the legal importance of adequate public participation in the 

state plan process, including public participation by affected 

communities. As previously discussed in this rule, recent 

studies also find that certain communities, including low-income 

communities and some communities of color are disproportionately 

affected by certain climate change related impacts. Because 

certain communities have a potential likelihood to be impacted 

by state plans for this rule, the EPA believes that the existing 

public participation requirements under 40 CFR 60.23 are 

effectuated for the purposes of this final rule by states 

engaging in meaningful, active ways with such communities. By 

requiring states to demonstrate they have meaningfully engaged 

with overburdened 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 
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include the required components described above. The EPA will 

propose and take final action on each state plan submittal in 

the Federal Register and provide an opportunity for notice and 

comment. When a state plan submittal is approved by the EPA, the 

EPA will codify the approved 111(d) state plan in 40 CFR part 

62. The following components of the state plan submittal will 

become the federally enforceable state 111(d) plan: 

 Federally enforceable emission standards for affected EGUs 

 Federally enforceable backstop of emission standards for 

affected EGUs 

 Implementing and enforcing measures for federally 

enforceable emission standards including EGU monitoring, 

recordkeeping and reporting requirements 

 State recordkeeping and reporting requirements 

E. State Plan Submittal and Approval Process and Timing 

1. Overview 

 In this action the EPA is finalizing that state plan 

submittals are due on August 31, 2016, which is 13 months after 

finalization of the emission guidelines. The EPA recognizes that 

because of state legislative schedules and rulemaking processes, 

coordination needed among states involved in multi-state plans, 

coordination with third parties, and the complex technical work 
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needed to develop a state plan, some states may not be able to 

develop a complete final plan submittal by 13 months after the 

final rule. However, various states have existing CO2 reduction 

programs in place, such as RE and demand-side EE measures, as 

well as state and regional programs designed to reduce CO2

pollution from EGUs. Furthermore, many states 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 and 

model rules for both rate and mass-based programs that states 

may wish to use. The EPA views these actions as positive steps 

that make the 13-month timeline achievable. 

However, in order to address the concern that 13 months is 

not sufficient time for states to prepare and submit a final 

plan submittal, 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 no later 

than August 31, 2018, for both single state and multi-state plan 

submittals. During the initial outreach process as well as the 

public comment period on the proposed rule, stakeholders 
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commented that additional time was needed to accommodate, among 

other things, state legislative and rulemaking schedules, 

coordination among states involved in multi-state plans, 

coordination with third parties, and the complex technical work 

needed to develop a state plan. The EPA recognizes that state 

administrative procedures can be lengthy, some states may need 

new legislative authority, and states planning to join in a 

multi-state plan will likely need more than 13 months to get 

necessary elements in place. Balanced against that concern, 

however, is the urgency of addressing CO2 emissions and the fact 

that there are certain steps the EPA believes states can take 

within 13 months to set themselves on a clear path to adoption 

of a final plan. We discuss the timing of state plans in more 

detail in this section below.

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 
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individual submittal for each participating state. The joint 

submittal must adequately address plan components that apply 

jointly for all participating states and for each individual 

state in the multi-state plan, including necessary state legal 

authority to implement the plan, such as state regulations and 

statutes. Because the multi-state plan functions as a single 

plan, each of the required plan components (e.g., plan emission 

goals, program implementation milestones, emission performance 

checks, and reporting) would be designed and implemented by the 

participating states on a multi-state basis. 

The EPA 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). 
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Under this approach, the combined common submittal and each of 

the individual participating state submittals would constitute 

the multi-state plan submitted for EPA review. The joint common 

submittal must be signed by authorized officials for each of the 

states participating in the multi-state plan and would have the 

same legal effect as an individual submittal for each 

participating state. 

Second, the EPA is finalizing an approach where all states 

participating in a multi-state plan separately make individual 

submittals that address all elements of the multi-state plan. 

These submittals would need to be materially consistent for all 

common plan elements that apply to all participating states, and 

would also address individual state-specific aspects of the 

multi-state plan. Each individual state plan submittal would 

need to address all required plan components. 

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 
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disruption to the submittals of the remaining participating 

states. These additional submittal approaches also facilitate 

multi-state plans where the participating states are 

coordinating the implementation of their plans but are not 

taking on a joint multi-state emission goal for affected EGUs. 

For example, states may seek to engage in a multi-state approach 

that links rate-based or mass-based emission trading programs 

through appropriate authorizations (e.g. reciprocity agreements, 

or state regulations) that allow affected EGUs to use emission 

allowances or RE/EE credits issued in one state for compliance 

with an emission standard in another state. 

In order to avoid a multi-state plan becoming unapprovable 

due to one state submitting an unapprovable portion of a multistate plan, withdrawing from the multi-state plan, or failing to 

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 
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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.703 For these 111(d) guidelines, the EPA is 

finalizing that each state must submit a final plan submittal to 

the EPA by August 31, 2016, (13 months after the final rule). 

The state may submit a final plan submittal by this date, or 

seek an extension to submit a final plan by submitting an 

initial plan submittal and a demonstration that additional time 

is needed to submit a complete plan. 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 steps the state has already taken to 

develop its plan and steps and a schedule for completing the 

necessary steps for submittal of a final plan by 2018. The EPA 

is also finalizing that a state must submit one progress update 

 

703 40 CFR 60.23(a)(1). 
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by August 31, 2017. States not needing the full two-year 

extension may submit earlier than the 2018 deadline, provided 

that a 2017 update is still submitted if the State’s timeline 

for completing a final goes beyond the 2017 update deadline. 

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 

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 
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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 

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 
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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 overburdened communities, 

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 intend to meaningfully engage 

with the public, including overburdened communities during the 

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

the final plan. Furthermore, states in their initial plan 

submittal and 2017 update must show how they identified 

overburdened communities with whom they are engaging as they 

develop their state plans. The EPA encourages states to use the 
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proximity analysis conducted for this rulemaking (which is 

described in section IX.A) as a tool to help them identify 

overburdened communities that could be potentially impacted by 

their plans. The EPA in its continued outreach with states 

during the implementation phase will provide resources to assist 

them in identifying overburdened communities. . 

For some recommendations on the steps that states could 

take to engage overburdened communities in a meaningful way, the 

agency recommends that states consult the EPA’s May 

2015,Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. In this document, the EPA 

defines meaningful involvement, as ensuring that, “potentially 

affected community members have an appropriate opportunity to 

participate in decisions about a proposed activity (i.e., 

rulemaking) that may affect their environment and/or health; 

the population’s contribution can influence the =EPA’s 

[regulatory authority’s] rulemaking decisions; the concerns of 

all participants involved will be considered in the decisionmaking process; and the EPA [decision-makers] will seek out and 

facilitate the involvement of those potentially affected by the 

Formatted: English (United States)
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EPA’s [or other regulatory authority’s] rulemaking process.”704

Additionally, this guidance document also encourages those 

writing rules consider the positive impacts that a rulemaking 

will have on communities).705 Another resource that the EPA 

recommends that states consult when devising their state plans 

is the document “Considering Environmental Justice in 

Permitting” available on the agency’s website.706 Both of the 

resources discussed above will provide states with assistance on 

how to effectively engage overburdened communities in the 

rulemaking process. 

The EPA recommends that as part of their meaningful 

engagement with overburdened communities, states work with 

overburdened 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 

 

704 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 705 Ibid. 706 Considering Environmental Justice in Permitting. 

http://www.epa.gov/environmentaljustice/planej/permitting.html#actions. 

Formatted: English (United States)

Formatted: English (United States)

Formatted: English (United States)
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must submit a letter to the EPA certifying that no such 

facilities exist by August 31, 2016.707 The EPA will publish a 

notice in the Federal Register to notify the public of receipt 

of such letters. 

If a state submits an acceptable initial plan submittal by 

August 31, 2016, with a request for an extension justified as 

specified in the plan guidelines, the EPA will grant the 

extension. 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 grant 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 

 

707 40 CFR 60.23(b). 
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for states submitting as part of a multi-state region. The EPA 

received substantive comment on the achievability of these 

proposed deadlines for state plan. Multiple commenters expressed 

concern that due to timing of legislative cycles (some of which 

are every 2 years), regulatory processes, and other necessary 

tasks, states would find it extremely difficult, if not 

impossible, to submit plans in 1 or 2 years, whether or not they 

were planning to submit as part of a multi-state region. The EPA 

agrees based on this input that a schedule shorter than 3 years 

will be 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. As noted above, 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. If a 
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full 2-year extension is requested and granted, that grant 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 begin the steps necessary to 

implement a federal plan. We address the substantive 

requirements of initial plans and 2017 updates in the next 

section. 

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 

initial plan submittal must contain a comprehensive roadmap 

outlining the path to completion, including milestones and 

dates. 
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During the public comment period, multiple commenters 

stated that the proposed timeframe for states to submit an 

initial state plan submittal was not achievable, citing, among 

other things, the number of decisions needed to be made by a 

state or states, and that the EPA needed to clarify the 

requirements for an initial state plan submittal. Multiple 

commenters also expressed concern that the requirements for an 

initial plan submittal required final decisions to be made by 

states, and that the initial plan submittal deadline was not 

enough time for states to make these decisions. In order to 

address the commenters’ concerns, the EPA is finalizing that in 

order for an extension to submit a final plan to be granted, 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: 

 A description of the status of each required component of 

the state plan, including what actions have already been 

taken, what steps remain, and the schedule for completing 

those steps. 

 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
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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 the affected public, 

including overburdened communities As part of this 

demonstration, states must describe how they engaged with 

overburdened communities 

 Demonstration of meaningful engagement and an opportunity 

for public comment by workers with jobs across the energy 

and efficiency sectors who have an interest in the state 

plan and communities whose economies are strongly 

influenced by energy sector dynamics. 

 The EPA proposed that appropriate justifications for 

seeking an extension beyond 2016 for submitting a final plan 

include: a state’s required schedule for legislative approval 

Formatted: Font: Times New Roman

Deleted: labor unions whose members are 

likely to be impacted by

Deleted: highly dependent on coal
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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 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, but 
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agrees there may be appropriate justifications states may submit 

in addition to the ones described in this final rule. The EPA is 

not finalizing other justifications in this final rule, however, 

if a state submits a justification not listed here, the EPA will 

determine whether such submission constitutes an appropriate 

justification 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 

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 
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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, or to indicate the status of the 

deliberation of this issue within the state. 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 pursue the 

single state approach. Commenters viewed this as being 

potentially problematic since, as proposed, a single state could 

only receive an extension until 2017, and if a multi-state plan 

effort does not work out the deadline for seeking the extension 

until 2017 would have passed. Finalizing a 2-year extension that 

is available for any state, whether they are pursuing an 

individual state plan or a multi-state plan resolves the 

commenters’ concern about conflicting extension deadlines if 

states involved in a multi-state effort decide not to pursue the 
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multi-state approach. 

In order for an extension request based on a state’s 

initial plan submittal to be granted, 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. Given the 

state’s request for additional time prior to putting in place 

enforceable measures to reduce CO2, it is reasonable and 

appropriate, and in keeping with the goals of 111(d) to ensure 

that any existing CO2 reduction measures remain in place. 

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 

by the procedural requirements of the implementing regulations 
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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). The EPA acknowledges the initial plan submittal 

might not include any legally enforceable provisions that the 

state would normally 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 appropriateinitial 

plan submittal justifying an extension for the final 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 
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plan submittal, it must provide the EPA with a response to any 

significant comments it received on issues relating to the 

initial plan so that the EPA can fully assess whether the 

extension request should be granted. 

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 (or steps already taken towards obtaining such 

agreements) 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. 

For states that request and receive approval for a full 2 

year extension, the state must submit an update halfway through 

that extension, by August 31, 2017. The 2017 update 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 final rule requires that the 

2017 update contain the following components: 

 A summary of the status of each component of the final 

plan, including an update from the 2016 initial plan 
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submittal and a list of which components are not 

complete. 

 A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), 

including draft or proposed legislation and/or 

regulations. 

 An updated comprehensive roadmap with a schedule and 

milestones for completing the plan, including progress to 

date in developing a final plan and steps taken in 

furtherance of actions needed to finalize a final plan. 

In order to assess if a state is on track to submit a final 

plan by the 2018 extension deadline, the EPA is requiring that 

the 2017 update must contain a summary of all components of a 

final plan, including a progress update on any incomplete 

components from the initial plan submittal, and a list of which 

components are still not complete. This progress update must 

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. 
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The EPA is also requiring that the 2017 update include a 

commitment to the type of plan approach the state will take in 

the final plan submittal. During the public comment period, many 

commenters stated that legislative action would be required to 

enact this final rule at the state level, and that the proposal 

did not provide enough time for legislative action or other 

regulatory actions needed for a state to be granted an 

extension. In order to respond to these comments, the EPA 

clarified that proposed or passed legislation or regulations are 

not required in the initial plan submittal. While a state may 

pursue multiple types of state plans in the initial 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 
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an updated comprehensive roadmap with a schedule and milestones 

for completing the plan. Similar to the requirement that the 

2017 update must include all components of a final plan, the 

update must include a demonstration that the state met the 

milestones for submitting a final plan that were outlined in the 

initial plan submittal. For any milestones that were not met, 

the state must provide a justification for not meeting the 

milestone and an updated schedule that demonstrates that the 

state is still on pace to meet the 2018 final plan submittal 

deadline. 

The EPA will assess a state’s 2017 update and, similar to 

the process for the initial plan submittal, notify the state 

within 90 days if the EPA determines that the state is not 

likely or able to meet the 2018 final plan submittal deadline. 

In the event that the EPA makes this determination for a state, 

the EPA will begin the federal plan development process to 

enforce and implement in the state. 

4. Process for EPA review of state plans 

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 
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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. 

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 
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provide for the EPA to act on a final plan within 4 months after 

the deadline for submission, which is consistent with versions 

of section 110 prior to the 1990 Amendments to the CAA. 40 CFR 

60.27(b). To be consistent with the current version of section 

110, the EPA intends to adopt a timeline of 12 months to review 

final plan submittals upon receipt of complete submittals, as is 

generally consistent with the timing requirements of section 110 

with respect to complete SIP submittals. Such a timeline would 

also provide the EPA with adequate time for review and 

rulemaking procedures, and ensuring an opportunity for public 

notice and opportunity for comment. We note, however, that we 

did not 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.708 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 

 

708 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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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 

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 we be further explain in the Federal Plan 
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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 

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. The EPA agrees, and is proposing to amend the 

implementing regulations as part of the rulemaking for the 

federal 111(d) plan. The EPA is not taking final action on these 

changes in this action. 

 The later timing for our action on partial 

approval/disapproval and conditional procedures does not create 

any issue with finalizing this rule. These procedural 

adjustments will only come into play after states have submitted 

their plans and the EPA is required to act on them and we intend 

to finalize these procedural changes prior to August 31, 2016, 

when the first plan submittals would occur. Until then, the EPA 
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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 

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. We refer to the Federal Plan proposal for 
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more details on how and when a Federal Plan would be triggered.

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 and we agree that 

this is an important aspect of this program. In this rulemaking, 

therefore, the EPA is finalizing that a state or states may 

revise its state plan. 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 

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 
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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 

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 
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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 that it does not interfere 

with the industry’s ability to maintain reliability. One such 

measure is that if a state cannot address a reliability issue 

within the boundaries of an approved state plan, the state can 

submit a request to the EPA to modify the state 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 that submissions 

related to this program be submitted electronically. 

Specifically, that includes negative declarations, state plan 

submittals (including any supporting materials that are part of 

a state plan submittal), any plan revisions, and all reports 

required by the state plan. The rule provides that files that 

are submitted to the EPA in an electronic format may be 

maintained by states in an electronic format. The submission of 

the information by the authorized official must be in a noneditable format. In addition to the non-editable version, the 

EPA is also requiring that all plan components designated as 
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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. Revisions to an approved plan. States shall provide the EPA 

with both a non-editable and editable copy of any submitted 

revision to existing approved federally enforceable plan 

components, including state plan backstop measures. The editable 

copy of any such submitted plan revision must indicate the 

changes made, if any, to the existing approved federally 

enforceable plan components, using a mechanism such as 

redline/strikethrough. This approach to identifying the changes 

made to the existing federally enforceable plan components is 
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consistent with the criteria for determining the completeness of 

SIP submissions set forth in Section 2.1(d) of Appendix V to 40 

CFR part 51. 

c. Electronic submittal. It is the EPA’s experience that 

electronic submittal of information has increased the ease and 

efficiency of data submittal and data accessibility. The EPA is 

developing the SPeCS, a web accessible electronic system to 

support this requirement that will be accessed at the EPA’s 

Central Data Exchange (CDX) (http://www.epa.gov/cdx/). The EPA 

will pre-register authorized officials and plan preparers in 

CDX. See section VIII.E.2 for additional information on the preregistration process for authorized officials and plan 

preparers. Detailed instructions for accessing CDX and SPeCS 

will be outlined in the “111(d) SPeCS User Guide: How to submit 

state 111(d) plan material to EPA” which will be available on 

the EPA’s Clean Power Plan Toolbox for States. The EPA will 

provide SPeCS training for states prior to the state plan 

submittal due date. 

Once in CDX, SPeCS can be selected from the Active Program 

Service List. The preparer (e.g., state representative compiling 

a state plan submittal) assembles the submission package. The 

preparer can upload files and complete electronic forms. 
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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 

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 
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document. In other words, the electronic signature is as equally 

enforceable as a paper signature. For more information on 

CROMERR, see the Web site: http://www.epa.gov/cromerr/. States 

who claim that a state plan submittal or supporting 

documentation includes confidential business information (CBI) 

must submit that information on a compact disc, flash drive, or 

other commonly used electronic storage media to the EPA. The 

electronic media must be clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local 

Programs Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703. 

The EPA received a number of comments on the electronic 

submittal of state plans. Some commenters preferred the option 

to submit electronically rather than the requirement to do so. 

In the final rule, for the reasons discussed below, the EPA is 

requiring electronic submittal of state plans and not allowing 

alternate options for plan submittal (e.g. paper submittal). 

Requiring electronic submittal is in keeping with current 

trends in data availability and will result in less burden on 

the regulated community. Electronic submittal will facilitate 

two-way business communication between states and the EPA, will 

guide states through the submittal process to ensure submission 

of all required plan components, and will enable states to 
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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. 

d. Plan templates. 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 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 
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state plan, how to assess the emission reductions delivered by 

RE and EE). The EPA has determined that the broad range of 

approaches states may take in preparing individual or multistate plans makes the development of specific templates 

challenging and likely not useful to states. However, the EPA is 

proposing model rules for both rate- and mass-based programs as 

well as a proposed Federal Plan. These effectively can serve as 

a template for states when preparing their state plan 

submittals. The EPA will continue extensive outreach to states 

and work closely with them on the need for additional tools and 

guidance to facilitate the development of approvable state 

plans. 

8. Legal basis regarding state plan process 

Section 111(d)(1) requires the EPA to promulgate procedures 

“similar” to those in section 110 under which states adopt and 

submit 111(d) plans. The EPA has interpreted this provision 

previously in the implementing regulations found in 40 CFR part 

60 subpart B. As discussed above, the EPA intends that planned 

revisions to the part 60 implementing regulations will clarify 

(among other things) whether certain procedures are appropriate 

for the EPA’s action on 111(d) state plans, and if so, precisely 

how those procedures should apply. The EPA is proposing these 
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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 
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for either an initial plan submittal or a final plan submittal 

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. 
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 With respect to the overall period of up to 3 years for 

submittals, we continue to find it reasonable and consistent 

with other deadlines in the CAA. First, section 110(a)(1) 

requires states to submit a plan for implementation, 

maintenance, and enforcement of new NAAQS within 3 years of 

promulgation of that NAAQS. This is true even if the EPA 

promulgates a NAAQS for a previously non-criteria pollutant. In 

that case, it is possible and even likely that at least some 

state agencies will lack statutory authority to regulate the new 

pollutant. Nonetheless, Congress dictated that states should 

submit section 110(a)(1) plans within 3 years. 

 Furthermore, we note that under subpart 1 of Part D of 

Title 1, attainment plans are generally due no later than 3 

years after designation of a nonattainment area, and under other 

subparts of Part D, plans are due even more quickly. For 

example, under subpart 4, attainment plans for particulate 

matter are generally due 18 months after designation, and under 

subpart 5, the same deadline applies for attainment plans for 

sulfur oxides, nitrogen dioxide and lead. While 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, 
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attainment plans must contain (among other things) a 

comprehensive inventory of sources of the relevant pollutant and 

its precursors (which in populated areas can be very numerous), 

control measures for those sources (including individualized 

control measures for the larger sources), and 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 
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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 

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 
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achieve the CO2 emission performance rates or state CO2 emission 

performance goal, and as explained above we can reasonably 

require the same of revisions. 

It is also reasonable to tailor the requirements of the 

demonstration to the magnitude of the revision. The EPA has 

taken a similar approach to tailoring the requirements for a 

technical demonstration that, under section 110(l), a SIP 

revision does not interfere with any applicable requirement 

concerning attainment of the NAAQS. If a SIP revision does not 

relax the stringency of any SIP measure, then the demonstration 

is simple. If the SIP revision does relax the stringency of SIP 

measures, then a qualitative or quantitative analysis may be 

necessary to show non-interference, depending on the nature of 

the revision, the current air quality in the area, and other 

factors. 

Finally, we proposed that revisions “should not result in 

reducing the required emission performance for affected EGUs 

specified in the original approved plan. In other words, no 

‘backsliding’ on overall plan emission performance through a 

plan modification would be allowed.” 79 FR 34917/1. We received 

adverse comments that this standard did not have a basis in 

section 111(d). According to commenters, since the standard for 
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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 

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 
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have schedules of compliance for each 2 calendar years starting 

in 2030 (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). If a 

backstop is triggered for a state measures plan, the schedule of 

compliance for the federally enforceable emission standards must 

begin no later than 18 months after the backstop is triggered 

and end at the end of the same compliance period. For example, 

if a backstop is triggered on July 1, 2025, the compliance 

period for the backstop emission standards must begin no later 

than January 1, 2027, and end on December 31, 2027. The next 

compliance period for the backstop emission standards would be 

January 1, 2028-December 31, 2029. 

In the June 2014 proposal, the EPA proposed that the 

appropriate averaging time for any rate-based emission standard 

for affected EGUs be no longer than 12 months within a plan 

performance period and no longer than 3 years for a mass-based 

standard. The EPA solicited comments on longer and shorter 

averaging times for emission standards included in state plans. 

The EPA received comments stating that the proposed 12 month 

averaging was too short and that there was no reason why the 

compliance period under a rate-based plan should be different 

from a mass-based plan. Comments stated that a multi-year 

averaging period is appropriate for rate-based and mass-based 
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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 

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. 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. If a state chooses to set shorter compliance periods 

we urge them to make efforts to be cognizant of other deadlines 

facing EGUs to assure that there will not be conflicts. The EPA 

recognizes that the compliance periods provided for in this 

rulemaking are longer than those historically and typically 

specified in CAA rulemakings. As reflected in long-standing CAA 

precedent, “[t]he time over which [the compliance standards] 
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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, 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 
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characteristics cited above: the long-lived persistence of CO2 in 

the stratosphere and the intent of these guidelines to address 

the long-term impacts. 

State plans must contain requirements for tracking and 

reporting actual plan performance during implementation, which 

includes reporting of CO2 emissions from affected EGUs. Affected 

EGUs must comply with emissions monitoring and reporting 

requirements that are largely incorporated from 40 CFR part 75 

monitoring and reporting requirements. The majority of affected 

EGUs are already familiar with the reporting requirements of 

part 75, and because of this, the EPA has chosen to streamline 

the applicable reporting requirements for 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. 
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In the June 2014 proposal, the EPA proposed that state 

plans must include monitoring, reporting and recordkeeping 

requirements for useful energy output from affected EGUs. 

Multiple commenters questioned whether gross rather than net 

electrical production should be reported by affected EGUs and 

recommended that the EPA should utilize gross rather than net 

generation. Many commenters recommended electricity be reported 

in the form used in the 111(b) rules for consistency between 

reporting requirements and simplification of calculation of 

emission limitations between new and old sources. Commenters 

also stated that to the extent the EPA seeks to provide guidance 

to states regarding its preferred monitoring and reporting 

procedures, the EPA should encourage states to avoid imposing 

additional monitoring and reporting burdens by taking advantage 

of the monitoring requirements that already exist to the 

greatest extent possible. For example, the commenters noted that 

the 40 CFR part 75 monitoring procedures used to comply with 

other programs, such as the Title IV Acid Rain Program, provide 

much of the data that would be needed to demonstrate compliance 

under the rule. Comments stated that the June 2014 proposal 

appeared to mandate a monitoring approach that would eliminate 

key flexibilities provided in the part 75 regulations, thus 
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requiring utilities to maintain separate document collection and 

reporting procedures and potentially eliminating important 

alternative monitoring options intended to ensure 

representative, cost-effective monitoring approaches are 

available. The commenters asked the EPA to revise its proposal 

to make clear that the procedures established under part 75 will 

suffice or explain the need for any exceptions. Commenters 

indicated that the rule should require all affected EGUs to 

monitor CO2 emissions and net hourly electric output under 40 CFR 

part 75, and report the data using the EPA's Emission Collection 

and Monitoring Plan System (ECMPS) assuring a more uniform 

monitoring and reporting process for all EGUs. The EPA believes 

that the final monitoring and reporting requirements (via ECMPS) 

address the issue of duplicative requirements and alleviate 

concern about lost flexibility raised by commenters. 

2. Plan performance demonstrations 

The state plan must include emission performance checks, 

and for state measures plans, periodic program implementation 

milestones. The state plan must provide for tracking of emission 

performance, and for measures to be implemented if the emission 

performance of affected EGUs in the state does not meet the 

applicable CO2 emission performance rates or state CO2 emission 
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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. A state may choose to define 

different interim step emission levels for achieving its 

required 2022-2029 average performance rate. The EPA recognizes 

the importance of ensuring that, during the 8-year interim 

period (2022-2029) for the interim performance rates or interim 

state goal, a state is making steady progress toward achieving 

the required level of emission performance. For both emission 

standards plans and state measures plans, the final rule 

requires periodic checks on overall emission performance leading 

to corrective measures or implementation of the backstop, if 

necessary, as described in section VIII.F.3 below. States must 

demonstrate that the interim steps were achieved, on average 

during 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 
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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 output709 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 

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). 

 

709 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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 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.710 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 

on a cumulative basis CO2 emissions from affected EGUs would not 

exceed what is allowable if the interim and final CO2 goals are 

achieved. 

 

710 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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 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 

unnecessary burdens on states and ensuring program 

effectiveness. In particular, the agency requested comment on 
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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 

states can design their state plans to receive the data and 
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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. The 

determination that a state is not on track to meet the 

applicable interim goal or interim step goals in 2022–2029 or 

the applicable final goal in 2030–2031 or later, or the CO2

emission performance rates, will be made through the actual 

performance checks to be included in state reports of 

performance data described in section VIII.D.2.a above. 

For emission standards plans, the final rule specifies that 

corrective measures must be enacted once triggered. 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 

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 
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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–

2031 or later, 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 
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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 that there are potential system emergencies that 

cannot be anticipated that could cause a severe stress on the 

electricity system for a length of time such that the multi-year 

requirements in a state plan may not be achievable by certain 

affected EGUs without posing an otherwise unmanageable risk to 

reliability. We are finalizing a reliability safety valve that 

will allow a state to modify the emission standards for an EGU 

or EGUs for a maximum of 90 days. The reliability safety valve 
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will allow the EGU or 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.G.2.e of this preamble. 

Multiple commenters supported the inclusion of strong 

enforcement measures for ensuring the interim and final goals 

are met, including the required use of corrective measures when 

triggered. Other commenters provided feedback as to the 

percentage that actual emission performance would need to exceed 

the level of emission performance specified in the statewide 

plan to trigger corrective measures. Some commenters supported 

the proposed trigger (actual emission performance that is not 

within 10 percent of the projected performance) that we are 
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finalizing, while some recommended a lower or higher trigger. 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). 

The EPA intends that planned revisions to the part 60 

implementing regulations will clarify (among other things) 
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whether the EPA has authority to call for plan revisions under 

section 111(d) when a state’s plan is not complying with the 

requirements of this guideline, and if so, precisely what 

procedures should apply. The EPA is proposing these revisions to 

the 111(d) implementing regulations in the notice of proposed 

rulemaking for the federal plan. The EPA is not taking final 

action now on this issue or the related change to the 

implementing regulations. 

a. Legal basis for corrective measures. The EPA discussed the 

concept of corrective measures in our 1992 General Preamble for 

the Implementation of Title I of the CAA Amendments of 1990. 57 

FR 13498 (Apr. 16, 1992). The General Preamble sets out four 

general principles that apply to all SIPs, “including those 

involving emissions trading, marketable permits and allowances.” 

Id. at 13568. The fourth principle, accountability, means (among 

other things) that “the SIP must contain means ... to track 

emission changes at sources and provide for corrective action if 

emissions reductions are not achieved according to the plan.” In 

the General Preamble, we noted that Part D of Title I explicitly 

provided for this in certain instances by requiring milestones 

and contingency measures. 

Some commenters noted that the contingency measures 
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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 
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performance to reflect less than the BSER over the long run.711 

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 

 

711 Similar considerations apply to the requirement under the 

state measures approach to revise the plan to make up the 

shortfall. 
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standards that necessarily achieve the performance rates or 

goal, even if the affected EGUs in the future vary in their 

relative amounts of electricity generated. Second, the state can 

set emission standards that are demonstrated to achieve the 

performance rates or goal based on assumptions about the 

relative amounts of electricity generated, but which may turn 

out to not actually achieve the goal. 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 
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based on application of the BSER during specified time periods. 

This raises the question of whether affected EGU emission 

performance should be maintained at the 2030 level – or instead 

should be further improved - once the final CO2 emission 

performance rate or state CO2 emission goal is met in 2030. This 

involves questions of performance rate and goal-setting as well 

as questions about state planning. The EPA believes that 

Congress either intended the emission performance improvements 

required under CAA section 111(d) to be maintained or, through 

silence, authorized the EPA to reasonably require maintenance. 

Other CAA section 111(d) emission guidelines set emission limits 

that do not expire. Therefore, the EPA is finalizing that the 

level of emission performance for affected EGUs represented by 

the final CO2 emission performance rates or state CO2 emission 

goal 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 

Deleted: permanent

Deleted: permanence

Commented [A22]: “permanent” could inadvertently suggest 

that the standards cannot be updated over time 
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goal if the plan measures used to demonstrate projected 

achievement of the final goal by 2030 will continue in force and 

not sunset. After implementation, the state is required to 

compare actual plan performance against the final goal on a 2-

year average basis starting in 2030, and to implement corrective 

measures or a backstop if triggered. 

 In the proposal, the EPA noted that “CAA section 

111(b)(1)(B) calls for the EPA, at least every eight years, to 

review and, if appropriate, revise federal standards of 

performance for new sources” in order to assure regular updating 

of performance standards as technical advances provide 

technologies that are cleaner or less costly. The proposal 

“requests comment on the implications of this concept, if any, 

for CAA section 111(d).” 79 FR 34830, 34908/3 (June 18, 2014). 

 We acknowledge the obligation to review section 111(b) 

standards as stated. The EPA is not finalizing any position with 

respect to any implications of this concept for section 111(d). 

We are promulgating rules for section 111(d) state plans that 

will establish standards of performance for existing sources to 

which a section 111(b) standard of performance would apply if 

such sources were new sources, within the definition in section 

111(a)(2) of “new source.” It is not necessary to address at 
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this time whether subsequent review and/or appropriate revision 

of the corresponding section 111(b) standard of performance have 

any implications for review and/or revision of this rule. 

a. Legal basis for maintaining emission performance. In the 

proposal, the EPA proposed “that the level of emission 

performance for affected EGUs represented by the final goal 

should continue to be maintained.” The EPA explained that 

“Congress either intended the emission performance improvements 

required under CAA section 111(d) to be permanent or, through 

silence, authorized the EPA to reasonably require permanence. 

Other CAA section 111(d) emission guidelines set emission limits 

to be met permanently.” 79 FR 34830, 34908/2 (June 18, 2014). We 

also requested comment on whether “we should establish BSERbased state performance goals that extend further into the 

future (e.g. beyond the proposed planning period), and if so, 

what those levels of improved performance should be.” Id. at 

34908/3. 

 We received adverse comment on establishing BSER-based 

state performance goals beyond the proposed planning period. 

Commenters argued that we did not have a sufficient basis at 

this time to determine what those future goals should be. We 

agree and have decided not to establish such goals. We are 
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finalizing, though, that the level of emission performance for 

affected EGUs represented by the final goal should continue to 

be maintained, for the reasons given in our proposal and quoted 

above. 

 The general structure of the CAA supports our 

interpretation. Section 111(d) plans establish standards of 

performance that reflect the BSER, a technology-based standard. 

Generally speaking, in the future technology will only improve, 

and correspondingly the CAA does not provide explicit processes 

to relax technology-based standards. In contrast, the provisions 

in Part D of title I that address attainment of health-based 

standards, the NAAQS, explicitly provide that once the NAAQS are 

attained, emission reduction measures may be relaxes so long as 

the NAAQS are maintained. The absence in section 111(d) of 

explicit provisions for future relaxation of emission reduction 

measures, as compared to Part D, supports our interpretation 

that the emission reductions continue to be on-going after the 

CO2 emission performance rates or state CO2 emission goals are 

achieved in 2030. This is consistent with our past practice for 

section 111(d) rules, which do not contain any provision that in 

the future removes or relaxes the promulgated guidelines. In 

light of the persistence of CO2 as a pollutant and its long-term 
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impacts, it is particularly critical in these guidelines to 

explicitly provide for continuing emission reductions. 

G. Additional Considerations for State Plans 

1. Consideration of a facility’s “remaining useful life” and 

“other factors” 

This section discusses the way in which the final emission 

guidelines address the CAA section 111(d)(1) provision requiring 

the Administrator, in promulgating 111(d) regulations, to 

“permit the State in applying a standard of performance to any 

particular source under a [111(d)] plan . . . to take into 

consideration, among other factors, the remaining useful life of 

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 
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to make additional goal adjustments based on remaining useful 

life and other facility-specific factors because they can fully 

consider these factors in designing their plans. 

a. Statutory and regulatory backdrop. This section describes the 

statutory and existing regulatory background concerning 

facility-specific considerations in implementation of section 

111(d). 

Section 111(d)(1)(A) requires states to submit a plan that 

“establishes standards of performance” for existing sources. 

Under section 111(d)(1)(B), the plan must also “provide for 

implementation and enforcement of such standards of 

performance.” Finally, the last sentence of section 111(d)(1) 

provides: “Regulations of the Administrator under this paragraph 

shall permit the State in applying a standard of performance to 

any particular source under a plan submitted under this 

paragraph to take into consideration, among other factors, the 

remaining useful life of the existing source to which such 

standard applies.” 

The EPA’s 1975 implementing regulations712 addressed a 

number of facility-specific factors that might affect 

requirements for an existing source under section 111(d). Those 

 

712 40 FR 53340 (Nov. 17, 1975). 
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regulations provide that for designated pollutants, standards of 

performance in state plans must be as stringent as the EPA’s 

emission guidelines. Deviation from the standard might be 

appropriate where the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control resulting from plant 

age, location, or basic process design; 

(2) Physical impossibility of installing necessary 

control equipment; or 

(3) Other factors specific to the facility (or class 

of facilities) that make application of a less stringent 

standard or final compliance time significantly more 

reasonable. 

This provision was amended in 1995 (60 FR 65387, December 

19, 1995), and is now prefaced with the language “Unless 

otherwise specified in the applicable subpart on a case-bycase basis for particular designated facilities or classes 

of facilities.” 40 CFR 60.24(f). 

b. Our proposal regarding the implementing regulations. Our 

proposal stated that the reference to “[u]nreasonable cost 

of control resulting from plant age” in 60.24(f) 

“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 

Formatted: Highlight
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noted that the prefatory language “unless otherwise 

specified in the applicable subpart” gives the EPA 

discretion to alter the extent to which the implementing 

rules applied if appropriate for a particular source 

category and guidelines. We requested comment on our 

analysis of the existing implementing regulations and any 

implications for our regulatory text in respect to how 

these guidelines relate to those regulations. 

 Commenters noted, among other things, that the sentence 

concerning “remaining useful life” was added in the 1977 CAA 

Amendments and that therefore it could not be said that 

provisions from the 1975 implementing regulations “implement” 

the sentence. The EPA does not think as a general matter that it 

is necessarily impossible that a pre-statutory amendment rule 

could continue to serve as a reasonable implementation of a 

post-statutory amendment provision. However, we also think it is 

appropriate, as we suggested in the June 2014 proposal, to 

specify in the applicable subpart for these guidelines that the 

provisions in 60.24(f) should not apply to the class of 

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 
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consideration is that, as we now explain, these particular 

guidelines “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” 

c. How these emission guidelines permit states to consider 

remaining useful life and other facility-specific factors. The 

EPA notes that, in general, the implementing regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 

similar to a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, and Kraft 

pulp plants specify emission limits for sources.713 In the case of 

 

713 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; 
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such emission guidelines, some individual sources, by virtue of 

their age or other unique circumstances, may warrant special 

accommodation. 

In these final guidelines for state plans to limit CO2 from 

affected EGUs, however, the agency does not specify presumptive 

performance rates for individual EGUs. Instead, these guidelines 

provide collective performance rates for two classes of affected 

EGUs (steam generating units and stationary combustion 

turbines), and give states the alternative of developing plans 

to achieve a state emission goal for the collective group of all 

affected EGUs in a state. Providing states with the ability to 

consider facility-specific factors such as remaining useful life 

in designing their state plans is one of the fundamental reasons 

that the EPA designed the final rule in this way. In addition, 

the significant revisions since proposal to address 

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 

 

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 practice can consider remaining useful life and other 

facility-specific factors in setting EGU requirements. Of 

course, EGUs vary considerably in age, so remaining useful life 

is potentially relevant to regulation of some units and not 

others. 

The guidelines capitalize on the inherent flexibility 

offered by aggregate EGU performance rates and by the state 

goals approach, allowing states flexibility on the form of the 

EGU standards that they include in CAA section 111(d) plans. A 

state could select a form of standards (e.g., marketable credits 

or permits, retirement of certain older facilities after their 

useful life, etc.) that avoids or diminishes concerns about 

facility-specific factors such as remaining useful life. Even if 

a state adopted the CO2 emission performance rates for fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, though, the state could take 

remaining useful life into consideration by allowing affected 

EGUs to comply using ERCs. In effect, under a trading program 

with repeating compliance periods, a facility with a short 

remaining useful life has a total outlay that is proportionately 

smaller than a facility with a long remaining useful life, 

simply because the first facility would need to comply for fewer 

Commented [A23]: Would it be possible to implement the two 

rates without using ERCs? 
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compliance periods and would need proportionately fewer ERCs 

than the second facility. Buying ERCs would avoid excessive upfront capital expenditures that might be unreasonable for a 

facility with a short remaining useful life, and would reduce 

the potential for stranded assets. 

In addition to providing states with flexibility on the 

form of the standards of performance in their plans, the 

guidelines leave to each state the design of the specific 

requirements that fall on each affected EGU in applying those 

standards. To the extent that an emission standard that a state 

may wish to adopt for affected EGUs raises facility-specific 

issues, the state may make adjustments to a particular 

facility’s requirements on facility-specific grounds, so long as 

any such adjustments are reflected (along with any necessary 

compensating emission reductions to meet the state goal) in the 

state’s CAA section 111(d) plan submission. 

Finally, we note that these guidelines permit states to use 

a rate or mass CO2 emission goal, and that each of these pathways 

allow states multiple design choices. Under either pathway 

states can take into consideration remaining useful life and 

seek to avoid stranded assets. 

d. Why remaining useful life and other facility-specific factors 

Deleted: could
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do not warrant adjustments in the guidelines’ performance rates 

and state goals. Under the final guidelines, remaining useful 

life and other facility-specific considerations do not provide a 

basis for adjusting the CO2 emission performance rates, or the 

state’s rate-based or mass-based CO2 emission goals, nor do they 

affect the state’s obligation to develop and submit an 

approvable CAA section 111(d) plan that adopts the CO2 emission 

performance rates or achieves the goal by the applicable 

deadline. After considering public comments discussed below and 

in the response to comments document, the EPA has retained this 

aspect of the proposed rule for the reasons described below. 

As noted above, the final guidelines provide aggregate 

emission goals for affected EGUs in each state, in addition to 

the CO2 emission performance rates. The guidelines also reflect a 

number of changes from proposal to address concerns about 

achievability of proposed state goals that were raised in public 

comments, many of which were explicitly prompted by 

consideration of the remaining useful life issue. The result is 

to afford states with broad flexibility to design requirements 

for affected EGUs to achieve the CO2 emission performance rates 

or state CO2 emission goals in ways that avoid requiring major 

capital expenditures, or imposing unreasonable costs, on those 
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affected EGUs that have a limited remaining useful life. State 

plans may use any combination of the emissions reduction methods 

represented by the building blocks, and may also choose to 

employ emission reduction methods that were not assumed in 

calculating state goals. 

To be more specific, the EPA notes that a state is not 

required to achieve the same level of emission reductions with 

respect to any one building block as assumed in the EPA’s BSER 

analysis. A state may use any combination of measures, including 

those not specifically factored into the BSER by the EPA. The 

EPA has estimated reasonable rather than maximum possible 

implementation levels for each building block in order to 

establish overall state goals that are achievable while allowing 

states to take advantage of the flexibility to pursue some 

building blocks more aggressively, and others less aggressively, 

than is reflected in the goal computations, according to each 

state’s needs and preferences. The guidelines provide further 

flexibility by allowing state plans to use emission reduction 

methods not reflected in the BSER. A description of multiple 

emission reduction methods is provided in section VIII.G. 

e. Response to key comments on remaining useful life. In 

response to the proposed guidelines, some commenters said that 
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the state goals were unachievable and therefore too stringent to 

provide states, as a practical matter, with the flexibility to 

consider remaining useful life for individual units. These 

commenters said the result would be premature retirements and 

stranded assets. 

In the final guidelines, the EPA has addressed the comments 

about lack of practical flexibility to consider remaining useful 

life by revising key elements of the guidelines in ways that 

will ensure that the EGU performance levels and state goals are 

achievable considering cost. At the same time, the final 

guidelines maintain the broad flexibility of each state to 

design its own compliance pathway, taking into account any 

facility-level concerns – including remaining useful life – in 

designing EGU requirements. 

The changes to the BSER and goal-setting methodologies 

include: 

 Starting the interim goal period in 2022 rather than 

2020, which allows more lead time for states and 

regulated entities and helps to ensure that the interim 

goal is achievable 

 Revising the goal-setting formula and the state goals 

themselves 
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 Updating analyses of achievable levels of improvement 

through the building blocks that together represent the 

BSER, while keeping them at reasonable, rather than 

maximum, levels 

 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 that could have made 

state goals less achievable for some states. 

Together, the changes described above help to ensure that 

the EGU performance rates and state goals established in the 

final guidelines are achievable. The EPA’s BSER analysis 

supports the conclusion that the final EGU performance rates and 

state goals are achievable through means that do not include 

retiring plants before the end of their useful lives; other 

means are available to reduce emissions at reasonable cost. This 

helps to illustrate that states, as a practical matter, will 

have flexibility to consider remaining useful life of individual 

EGUs in designing requirements for EGUs in their state plans. 

Commented [A24]: Could EPA provide more discussion of how 

the analysis supports this conclusion? 
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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. 

Several commenters said that that the statute does not 

authorize the EPA to require other facilities to achieve greater 

reductions to compensate for a facility that warrants relief 

based on remaining useful life. One said that consideration of 

remaining useful life and other relevant factors is a one-way 

ratchet that provides relief to sources that cannot achieve the 

BSER, and that the EPA turns that approach on its head by 

prohibiting a state from providing such relief to a specific 

facility unless it can identify another facility to “punish” by 

requiring additional emissions reductions to offset that relief. 

The EPA disagrees with these comments, many of which appear 

to be predicated on an approach not taken in this rule: 

requiring states to set presumptive standards for individual 

affected EGUs. The EPA is not establishing BSER for individual 

facilities, and then requiring better-than-BSER from some 

Commented [A25]: It might help to define what EPA means 

here by stranded assets – as some commenters may believe it means 

retirement of any plant before it would have retired under BAU 
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facilities to make up to worse-than-BSER performance that a 

state authorizes for other facilities because of a short 

remaining useful life. Rather, as previously noted, the 

guidelines set aggregate performance rates and state goals that 

represent the aggregate emission level of affected EGUs in each 

state based on estimates of the aggregate impact of applying the 

BSER. In estimating the amount of improvement achievable through 

each building block e.g., improvement in heat rate or amount of 

generation shift to lower-emitting EGUs), the EPA relies on 

estimating the average achievable level rather than attempting 

to estimate the level achievable by each and every affected EGU. 

Thus, the fact that an individual facility may be unable, for 

example, to achieve the average level of heat rate improvement 

assumed in goal-setting is consistent with the EPA’s analysis, 

and does not undermine the EPA’s determination of state goals. 

An additional reason that the EPA believes that 

consideration of remaining useful life and other facilityspecific factors does not warrant adjustments to state goals is 

that the design of the guidelines does not mandate that states 

impose requirements that would call for substantial capital 

investments at affected EGUs late in their useful life. Of the 

building blocks considered by the EPA in developing state goals, 
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only the first block, heat rate improvements, involves capital 

investments at the affected EGUs. The other building blocks – 

generation shifts among affected EGUs, and addition of new RE 

generating capacity – do not generally involve capital 

investments by the owner/operator at an affected EGU. 

In the case of heat rate improvements at affected EGUs, 

states can choose whether to require a greater or lesser degree 

of heat rate improvement than the percentage improvement assumed 

in the EPA’s BSER determination, either because of the remaining 

useful life of one or more EGUs, other source-specific factors 

that the state deemed appropriate to consider, or any other 

relevant reasons. The agency also notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

to remove sulfur dioxide; a fleet-wide average cost for heat 

rate improvements based primarily on best practices at coalfired generating units would not likely exceed $100/kW, compared 

with a typical SO2 wet scrubber cost of $500/kw (costs vary with 

unit size).714 In addition, the proposed guidelines allow states 

 

714 Heat rate improvement methods and related capital costs are 

discussed in the GHG Abatement Measures TSD; SO2 scrubber capital 

costs are from the documentation for the EPA’s IPM Base Case 
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to regulate affected EGUs through flexible regulatory approaches 

that do not require affected EGUs to incur large capital costs 

(e.g., averaging and trading programs). Under the EPA’s proposed 

approach - establishing state goals and providing states with 

flexibility in plan design – states have flexibility to make 

exactly the kind of judgments necessary to avoid requiring 

capital investments that would result in stranded assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant as states 

determine requirements that are directly applicable to affected 

EGUs. If relief is due a particular facility, the state has an 

available toolbox of emission reduction methods that it can use 

to develop a section 111(d) plan that will achieve the CO2

emission performance rates or state CO2 emission goals on time. 

The EPA therefore concludes that the remaining useful life of 

affected EGUs, and the other facility-specific factors 

identified in the existing implementing regulations, should not 

be regarded as a basis for adjusting the CO2 emission performance 

rates or a state CO2 emission goal, and should not relieve a 

state of its obligation to develop and submit an approvable plan 

 

v5.13, Chapter 5, Table 5-3, available at 

http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf. 
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that achieves that goal on time. 

f. Legal considerations regarding remaining useful life. Section 

111(d)(1) requires the EPA in promulgating section 111(d) 

regulations to “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” Here, we discuss the legal basis 

for determining that the emission guidelines are consistent with 

this statutory requirement. 

First, the phrase “remaining useful life” also appears in 

the visibility provisions of section 169A. There, in determining 

best available retrofit technology (BART), the state (or the 

EPA) must take into consideration (among other factors) “the 

remaining useful life of the source.” 42 USC 7491(g)(2); see 

also id. (g)(1) (reasonable progress). In the context of the 

visibility program, we have interpreted this provision to mean 

that the remaining useful life should be considered when 

calculating the annualized costs of retrofit controls. See 40 

CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost is then 

used to determine a cost effectiveness, in dollars per ton of 

pollutant removed on an annual basis. As a result, a technology 

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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 

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 

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(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 

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 

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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 

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. 

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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 industry’s ability to maintain the 

reliability of the nation’s electricity supply. Comments from 

state, regional and federal reliability entities, power 

companies and others, as well as consultation with the 

Department of Energy (DOE) and Federal Energy Regulatory 

Commission (FERC), helped inform a number of changes made in 

this final rule to address reliability. In addition, FERC 

conducted one national and three regional technical conferences 

on the proposed rulein which the EPA participated and at which 

the issue of reliability was raised by numerous participants. 

 As discussed throughout the preamble and TSDs, the 

electricity sector is undergoing a period of intense change. 

While the change in the resource mix has accelerated in recent 

years, wind, solar, other RE, and EE resources have been 

reliably participating in the electric sector for a number of 

years. Many of the potential changes to the electric system that 

Commented [A26]: “a wide” might be more precise 

Commented [A27]: might be useful to note that these comments 

were also taken into consideration in the final design 
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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 

local or regional reliability issue. These include transmission 

system upgrades, installation of new generating capacity, 
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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.715 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.716 Mandatory reliability standards apply to 

how the bulk electric system is planned and operated. For 

example, transmission operators and balancing authorities have 

 

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

Systems: An Overview of the Technology, the Marketplace, and 

Government Regulations, IEEE Press, at 160 (2010). 716 Id. 
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to develop, maintain, and implement a set of plans to mitigate 

operating emergencies.717 

As the electricity market changes and new challenges 

emerge, electric system regulators and industry participants 

make changes to how the electric system is designed and operated 

to respond to these challenges For example, expressing 

reliability and rate concerns about fuel assurance issues, FERC 

recently issued an order requiring ISOs/RTOs to report on the 

status of their efforts to address market and system performance 

associated with fuel assurance.718 In February of 2015, 

Midcontinent Independent System Operator (MISO), California 

Independent System Operator Corporation (CAISO), New York 

Independent System Operator (NYISO), Southwest Power Pool (SPP), 

ISO New England (ISO-NE), and PJM Interconnection (PJM) each 

filed a report with FERC highlighting their efforts to respond 

to fuel assurance concerns.719 This is just one of many examples 

 

717 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at 

http://www.nerc.net/standardsreports/standardssummary.aspx. 

718 Centralized Capacity Markets in Regional Transmission 

Organizations and Independent System Operators, 149 FERC ¶ 

61,145 (2014). FERC generally defines fuel assurance as 

“generator access to sufficient fuel supplies and the firmness 

of generator fuel arrangements”. Id. P 5. 719 For example, ISO-NE and PJM each filed “pay-for-performance” 

proposals to address fuel assurance in their regions. FERC 
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where electric system regulators and industry participants 

recognized a potential reliability issue and are proactively 

searching for solutions. 

The EPA’s approach in this final rule is consistent with 

our commitment to ensuring that the final rule does not 

interfere with the industry’s ability to maintain the 

reliability of the nation’s electricity supply. Many aspects of 

the final rule’s design are intended to support system 

reliability, especially the long compliance period and the basic 

design that allows states 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. Despite the flexibility built into the design of the 

proposal, and the long compliance trajectory, many commenters 

have expressed concerns that the proposed rule could jeopardize 

electric system reliability. We note that the EPA has received 

 

recently acted on ISO-NE market rule changes providing increased 

market incentives in capacity, energy, and ancillary services 

markets for generators to be available to meet their obligations 

during reserve shortages. ISO New England Inc., 147 FERC ¶ 

61,172 (2014). Additionally, FERC conditionally approved a PJM 

“pay-for-performance” proposal that creates a new capacity 

product to provide greater assurance of delivery of energy and 

reserves during emergency conditions, establishing credits for 

superior performance and charges for poor performance. PJM 

Interconnection, L.L.C., 151 FERC ¶ 61,208 (2015). 
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similar comments in EPA rulemakings dating as far back as the 

1970s. The EPA has always and continues to take electric system 

reliability comments seriously and despite these reoccurring 

comments with regard to reliability, the electric industry has 

done an excellent job of maintaining reliability including when 

it has had to comply with environmental rules with much shorter 

compliance periods, higher costs, and much less flexibility than 

this final rule. Now, more than ever, the electric industry has 

tools available to maintain reliability, including mandatory and 

enforceable reliability standards.720 

 

720For example, then Executive Vice President-Markets and current 

President of PJM, an RTO with a substantial amount of coal-fired 

capacity and generation, Andrew Ott discussed the success of 

PJM’s market design in assuring that PJM met and exceeded target 

reserve margins while MATS was being implemented. See Statement 

of Andrew Ott, PJM Executive Vice President-Markets, FERC 

Technical Conference on Centralized Capacity Markets in Regional 

Transmission Organizations and Independent System Operators, 

AD13-7-000, at 3, 7 (Sept. 25, 2013), available at 

http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6944&CalT

ype= &CalendarID=116&Date=09/25/2013&View=Listview. At the FERC 

national Clean Power Plan Technical Conference, Michael J. 

Kormos, PJM Executive Vice President-Operations, said that PJM’s

markets have proven, “resilient enough to respond to different 

policy initiatives. . . Whether it is the Sulfur Dioxide Trading 

Program of the 1990’s, the MATS rule or individual state RPS 

initiatives, the markets have been able to send the appropriate 

price signals that produce competitive outcomes.”See Michael J. 

Kormos, PJM Executive Vice President, Statement at FERC 

Technical Conference on EPA’s Clean Power Plan, AD15-4-000, at 3 

(Feb. 19, 2015), available at 
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As with numerous prior CAA regulations affecting the 

electric power sector, environmental requirements for this 

industry are accommodated within the existing extensive 

framework established by federal and state law to ensure that 

electricity production and delivery are balanced on an ongoing 

basis and planned sufficiently to ensure reliability and 

affordability into the future. In addition, changes that the EPA 

is making in this final rule respond directly to the comments 

and the suggestions that we received on reliability and provide 

further assurance that implementation of the final rule will not 

create reliability concerns. 

First, the final rule allows significant flexibility in how 

the applicable CO2 emission performance rates or the statewide 

CO2 goals are met. Given the differing characteristics of the 

electric grid within each state and region, there are many paths 

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 

 

http://www.ferc.gov/CalendarFiles/20150213081650-

Kormos,%20PJM.pdf. 
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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. 

Additionally, the final rule offers opportunities for trading 

among affected EGUs within and between states, and other multistate compliance approaches that will further support electric 

system reliability. 

Second, the final rule provides sufficient time to ensure 

system reliability. The final rule retains the 2030 date for the 

final period, which commenters largely supported as reasonable 

and not a concern for reliability, and addresses one of the key 

issues that commenters pointed to as a reliability-related 

concern by both moving the start of the interim period from 2020 

to 2022 and adjusting the interim goals to provide a less 

dramatic initial reduction requirement and a more gradual glide 

path to the final 2030 goals. Both FERC’s May 15, 2015 letter 

and the comment record made it clear that providing sufficient 

time for planning and implementation was essential to ensuring 
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electric system reliability. The EPA has responded by provided 

additional time to allow for planning and implementation of the 

final rule requirements, while at the same time allowing enough 

time between the beginning of the implementation plan and 2030 

to achieve state goals. We note that the final rule does not 

require that all states have met their interim goal by 2022 but 

rather that they meet it on average during the 2022 to 2029

period. 

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 eightyear period from 2022 to 2029 to meet interim goals. Moreover, 

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

August 31, 2016, we recognize that some states may need more 

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

final state plans, including consideration of reliability. 

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

Deleted: 2024

Commented [A28]: given that states can still set their own glide 

paths across the entire period, it seems helpful to describe the entire 

period as providing additional flexibility 
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process for state plans. If the 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 that 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. 

Third, we are including in the final rule a requirement 

that each state demonstrate in its final state plan submittal 

that it has considered reliability issues in developing its 

plan. This was suggested by a number of commenters, and we agree 

that it is a useful element to state plan development.Fourth, 

the final rule provides a mechanism for a state to 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. 

Fifth, in response to a variety of comments, we are 

providing a reliability safety mechanism that provides a path 
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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 comply with 

modified emission standards to respond to this kind of 

reliability concern. 

Sixth and finally we are committed to maintaining an 

ongoing relationship with FERC and DOE as this final rule is 

implemented to ensure continued reliable electric generation and 

transmissions. 

We provide more details about these various elements of the 

final rule, as well as other features of the rule that support 

system reliability, below. 

a. Summary of key comments. The EPA received a number of 

comments regarding the proposed rule and electric reliability. 

Many commenters provided specific, useful ideas regarding 

changes that could be made to the proposal to specifically 

address their reliability concerns. For example, many commenters 

state that allowing additional time to comply could help in 

meeting the final rule requirements while addressing their 

reliability concerns. Some commenters suggest that additional 

time would allow them to evaluate potential reliability impacts 

and system changes that need to be made to comply with final 
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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, consulted further with FERC and incorporated many of 

the suggested changes in this final rule. 

b. Final rule flexibility. In issuing this final rule, the EPA 

considered public comments on the potential interaction between 

the proposal and electric reliability. While we have made every 

effort to develop guidelines that would steer clear of potential 

reliability disruptions, a number of commenters argued that the 

Commented [A29]: is the RSV available to states with trading 

programs? Like the FP, it seems like it would be logical that it 

would be unnecessary or that it should be constrained to situations 

where the “extra” emissions are made up later in the program. 
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possibility of an unanticipated reliability event cannot be 

entirely eliminated. Given the complexity of the electric grid, 

electric system planners and operators will likely not 

completely avoid reliability issues, even in the absence of 

these guidelines. The EPA designed the final rule to ensure to 

the greatest extent possible that actions taken by states and 

affected EGUs to comply with the final rule do not increase 

potential reliability issues or complicate their resolution. In 

fact, to the extent that meeting final rule requirements results 

in the reduction of demand, upgrades in transmission efficiency 

and infrastructure, and investment in 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 and adjusting the interim goals to 

provide a less dramatic initial reduction requirement and a more 
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gradual glide path to the final 2030 goals. This gradual 

application of the BSER over the 2022-2029 interim period 

provides the state with substantial latitude in selecting its 

own emission reduction glide path over that period.721 As noted 

above, the final rule also provides states with up to 3 years to 

adopt and submit their final state plans, and afterwards states 

can, if necessary, revise their plans before the beginning of 

the interim period. This timing gives system planners and 

operators the opportunity to do what they have already been 

doing; looking ahead to forecast potential contingencies that 

pose reliability risks and identifying those actions needed to 

mitigate those risks. The final rule allows states to develop a 

pathway over the interim period that reflects their own 

circumstances, such as reflecting planned additions and changes 

in generation mix and potentially taking advantage of 

opportunities for trading of credits or allowances by affected 

EGUs within and between states. Because achievement of the 

emission rates or goals can be demonstrated over several years, 

state plans can accommodate situations where for example, it may 

take time to develop new generation, pipelines, or transmission 

 

721 Also, we separated the glide path into three steps, 2022-

2024, 2025-2027, and 2028-2029, that is also achievable “on 

average” over the 8-year interim period. 
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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 final state plan submission 

that it has considered reliability issues while developing its 

plan in order to ensure that standards of performance can be 

implemented and enforced. If system reliability is threatened, 

the ability of affected EGUs to meet the requirements of this 

final rule could be compromised if they are required to operate 

beyond the emission standards set in state plans in order to 

maintain the reliability of the electric grid. The requirement 

that states consider reliability as part of the development of 

state plans is designed to ensure that state plans are flexible 

enough to avoid this kind of potential conflict between 

maintaining reliability and implementing emission standards for 

affected EGUs. 

A number of commenters, notably ISOs and RTOs, pointed out 

that planning and anticipation of change are among the essential 

ingredients of ensuring the ongoing reliability of the 
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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, EPA recommends that the state request that 

the planning authority review the state plan at least once 

during the plan development stage and provide its assessment of 

any reliability implications of the plan. Additionally, we 

encourage states that are considering reliability through an 

ISO/RTO or other planning authority consultation process to have 

a continuing dialogue with those entities during development of 

their final state plan. While following the recommendations of 

the planning authority would not be mandatory, the state should 

Deleted: should
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document its consultation process, any response and 

recommendations from the planning authority, and the state’s 

response to those recommendations in its final state plan 

submittal to the EPA. This consultation is designed to inform 

how the state might adjust its plan for meeting the CO2 reduction 

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 final state plan, a 

state may provide other comparable support for a demonstration 

that it has considered reliability during the state plan 

development process.722 The EPA believes that this requirement to 

demonstrate consideration of reliability will provide an 

effective reliability evaluation in the state plan development 

process. It should further help states avoid any conflicts 

between state plans and the maintenance of reliability during 

implementation of the state plan and associated emission 

standards. Finally, we also encourage states as they develop 

their plans to consider, to the extent possible, other potential 

 

722 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. 

Deleted: essential
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issues that may impact affected EGUs. For example, an affected 

EGU may be in an ISO/RTO that puts certain deadlines on 

generators that may not line up perfectly with state plan 

deadlines. 

d. State plan modifications. If, during the implementation of a 

state plan, a reliability issue cannot be addressed within the 

range of actions or mechanisms encompassed in an approved state 

plan, the state can submit a plan revision to the EPA to amend 

its plan. In such a circumstance, the state plan may need to be 

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 unlikely to face 

a potential conflict between state plan requirements and the 

maintenance of reliability. States that participate in multistate 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 

Deleted: less likely

Commented [A30]: Ensuring consistency with the relevant 

discussion in the federal plan proposal re market-based plans and 

reliability safety valve seems important 
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revisions. It may also be the case that facility-specific 

emissions standards in a state plan are proving to be too 

inflexible to allow the plan to accommodate market or other 

changes in the power sector. In such instances, there should be 

a lead time between the announced retirement of the unit and the 

need to amend the state plan. Therefore, the state should be 

able to utilize the revisions process that the EPA provides. 

The EPA will review a plan revision per the requirements of 

40 CFR part 60. If the state’s request for a state plan revision 

must be addressed in an expedited manner to assure a reliable 

supply of electricity, the state must document the risks to 

reliability that would be addressed by the plan revision by 

providing the EPA with a separate analysis of the reliability 

risk from the ISO/RTO or other planning authority. This analysis 

should be accompanied by a statement from the ISO/RTO or other 

planning/reliability authority that there are no practicable 

alternative resolutions to the reliability risk. In this case, 

the EPA will conduct an expedited review of the state plan 

revision. 

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 
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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 

that severe weather or other short-term events could 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 will be demonstrated over 2-3 years, such a shortterm 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 
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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 operate 

under modified emission standards to respond to this kind of 

reliability concern. For example, 1) a catastrophic event 

damages critical or vulnerable equipment necessary for reliable 

grid operation; or 2) a major storm floods and causes severe 

damage to a large NGCC plant so that it must shut down.; or 3) a 

large nuclear unit must cease generating so that other affected 

EGUs must run at higher levels. 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)without authorizing the 

use of allowances or credits, and may trigger the need for 

immediate, short-term relief from those facility-specific 

requirements. In such an instance, the final rule provides a 

process to ensure that system reliability will not be 

compromised. 

Commented [A31]: Could EPA discuss further these dynamics 

in the context of a nuclear plant retirement? 

Is the state required to “make up” the excess emissions? 
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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.. 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. However, the EPA 

reserves the right to review such notification, and in the event 

that the EPA finds such notification is improper, the EPA may 

disallow the short-term modification and affected EGUs must 

operate under the approved state plan emission standards. The 

notification to the EPA must be in writing and addressed to the 

appropriate EPA regional office. It must include a full 

description of the reliability concern and why an unforeseen, 

emergency situation that threatens reliability requires the 

affected EGU (or EGUs) to operate under modified emission 

standards from those originally 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 reliability 
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coordinators and planning authorities to alleviate the problem 

in an expedited manner. The state should also include a written 

concurrence from the relevant reliability coordinator and/or 

planning authority confirming the existence of the imminent 

reliability threat and supporting the temporary modification 

request or an explanation of why this kind of concurrence cannot 

be provided. Additionally, if the relevant planning authority 

has conducted a system-wide or other analysis of the reliability 

concern, the state 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 or EGUs needing to operate in a 

way that ensures system reliability. For those 90 days the 

emissions of the affected EGU or EGUs will not be counted 

against the state’s over goal. Such a modification may not 

alter or abrogate any other obligations under the approved state 

plans for the requisite state goal or performance rates to be 
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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 If 

there still is a serious, ongoing reliability issue, the state 

must provide to the EPA a notice that it will be submitting a 

state plan revision. At the end of this period of 90 days or 

less, the emission standards originally approved under the state 

plan must be back in effect for the affected EGUs, but EPA will 

work with the state to provide a reasonable pathway for the 

state to resume meeting its obligations. 

The EPA intends for this reliability safety valve to be 

used only in exceptional situations. 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 
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of the reliability safety valve, or if problems come up a second 

time, the state must submit a revision to its state plan 

according to section VIII.F.6, so that the state plan is 

flexible enough to assure that such conflicts do not recur. The 

EPA believes that finding a long-term solution to potential 

major reliability issues, such as the state amending its plan to 

provide needed flexibility, is better for system reliability 

than the state facing multiple emergency events not contemplated 

in its plan and scrambling to respond. 

f. Coordination among federal partners. The EPA, DOE, and FERC 

have agreed to coordinate efforts to help ensure continued 

reliable electricity generation and transmission during the 

implementation of the final rule. The three agencies have 

developed a coordination strategy that reflects their joint 

understanding of how they will work together to monitor final 

rule implementation, share information, and resolve any 

difficulties that +may be encountered. This strategy is based on 

the successful working relationship that the three agencies 

established in their joint effort to work together to monitor 

reliability during MATS implementation. 

g. Analyses of the reliability impacts of the proposal. The EPA 

appreciates that a large number of entities from many different 
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industry perspectives have published reports and analysis with 

respect to electric reliability and the 111(d) proposed rule. We 

take concerns about reliability very seriously, and we 

appreciate the attention given to this issue. It is important to 

note that these studies were conducted prior to promulgations of 

this final rule, and thus were only able to consider electric 

reliability with respect to the proposal. The EPA has made 

changes and improvements to the proposal in response to comments 

and new information, and some of the changes are relevant to the 

final rule’s potential effect on electric reliability. One 

notable change pertains to the start of the interim period, 

which is now 2022 rather than 2020. Another important change to 

the final rule is a more gradual phase-in of BSER for sources 

over the interim compliance period (from 2022 through 2029). The 

final rule also provides considerable flexibility and multiple 

pathways to states, including allowing the use of trading and 

other approaches, that would allow essential units to continue 

to generate as long as their compliance obligation is met under 

each state’s (or region’s) plan. In addition, we have included a 

reliability safety valve provision that can be utilized in 

certain emergency situations as part of the final rule. These 

changes, in addition to already existing industry mechanisms and 
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planning requirements, will help to ensure that industry will be 

able to maintain electric reliability. The EPA is confident that 

the final rule will cut harmful electric power plant pollution 

while maintaining a reliable electric grid because the final 

rule provides industry with the time and flexibility needed to 

continue its current and ongoing planning and investing to 

modernize and upgrade the electric power system. 

 In June of 2015, M.J. Bradley & Associates issued a report 

that enumerated a set of useful guiding principles for studying 

and evaluating the reliability impacts of the final rule.723 The 

report enumerated six principles: (1) a study should be 

transparent about the assumptions and data used; (2) a study 

should accurately reflect the existing status of the grid in its 

modeling assumptions; (3) a study should clearly identify the 

base case and not confuse what will happen as a result of the 

final rule with what would have happened anyway; (4) where 

possible, a study should contain sensitivities and probabilities 

as they are looking into the future which is necessarily 

uncertain; (5) a study should reflect the flexibility provided 

to states to allow them to design compliance approaches to 

 

723 M.J. Bradley & Associates, Guiding Principles for Reliability 

Assessments Under EPA’s Clean Power Plan (June 3, 2015), 

available at http://www.mjbradley.com/node/295. 
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maximize reliability; and (6) a study should provide realistic 

and reliability-focused results. These principles are helpful to 

keep in mind when reviewing recent studies. 

 NERC published its analyses of the proposed rule in 

November 2014 and again in April 2015.724 The EPA appreciates 

NERC’s attention to, and interest in, the proposed rule. 

However, we note that like some other studies, NERC assumes 

considerably less flexibility than actually exists. The final 

rule provides states with considerable time and flexibility to 

design plans that are tailored to states’ power sector, which 

should be reflected in any reliability analysis. Also, the NERC 

study does not fully reflect the current electric grid. For 

example, the amount of renewable generation that NERC assumes 

for 2020 is similar to levels of generation that we see today. 

Further, NERC conflates retirements that may happen as a result 

 

724 North American Electric Reliability Corporation, Potential 

Reliability Impacts of EPA’s Proposed Clean Power Plan (Nov. 5, 

2014), available at http://www.nerc.com/news/Pages/ReliabilityReview-of-Proposed-Clean-Power-Plan-Identifies-Areas-forFurther-Study,-Makes-Recommendations-for-Stakeholders.aspx; 

North American Electric Reliability Corporation, Potential 

Reliability Impact of EPA’s Proposed Clean Power Plan: Phase 1

(Apr. 21, 2015), available at

http://www.nerc.com/news/Pages/Assessment-Uses-ScenarioAnalysis-to-Identify-Potential-Reliability-Risks-from-ProposedClean-Power-Plan.aspx. 
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of the rule with those that are already planned. Brattle has 

also reviewed NERC’s November 2014 initial analysis of the 

proposed rule, noting that it is important to distinguish 

between concerns about the building blocks and reliability 

concerns about compliance with state plans.725 Brattle concluded 

that there are real world solutions to NERC’s concerns. These 

include making use of the many flexible options available to 

states under the rule to mitigate reliability risks. 

 Multiple ISOs/RTOs also provided analyses of the proposed 

rule, including MISO, PJM, ERCOT, and SPP.726 For example, MISO 

conducted an analysis of coal units at risk for retirement, 

 

725 Brattle Group, EPA’s Clean Power Plan and Reliability, 

Assessing NERC’s Initial Reliability Review (Feb. 2015), 

available at http://info.aee.net/hs-fs/hub/211732/file2486162659-pdf/PDF/EPAs-Clean-Power-Plan--ReliabilityBrattle.pdf?t=1434398407867. 

726 See MISO, Analysis of EPA’s Proposal to Reduce CO2 Emissions 

from Existing Units (Nov. 12, 2014), available at

https://www.misoenergy.org/Library/Repository/Communication%20Ma

terial/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions

.pdf; PJM, PJM Interconnection Economic Analysis of the EPA 

Clean Power Plan Proposal (Mar. 2, 2015), report listed at

http://www.pjm.com/documents/reports.aspx; SPP, SPP’s 

Reliability Impact Assessment of the EPA’s Proposed Clean Power 

Plan, (Oct. 8, 2014), available at

http://www.spp.org/publications/CPP%20Reliability%20Analysis%20R

esults%20Final%20Version.pdf; ERCOT, ERCOT Analysis of the Clean 

Power Plan (Nov. 17, 2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf; and 
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finding that 14 GW of coal may be at risk.727 SPP performed a 

resource adequacy analysis that assumes planned retirements plus 

the EPA’s projected retirements, but did not similarly account 

for the building of new generation capacity.728 While we 

appreciate MISO’s and SPP’s concerns regarding retirements and 

the potential that reserves will fall below reserve requirement 

levels, it is important to consider the many ways in which 

states can develop plans that account for their potential 

reliability concerns. The final rule continues to give states 

significant flexibility in how they comply with requirements, 

including both BSER and non-BSER measures as a means to comply. 

For example, energy efficiency measures can greatly assist 

states and affected EGUs in meeting the standards and/or state 

plan. Many studies assume that state plans will simply apply 

BSER and do not recognize the large number of compliance 

approaches and opportunities that states and sources have 

 

727 MISO, Analysis of EPA’s Proposal to Reduce CO2 Emissions from 

Existing Units, at 14 (Nov. 12, 2014), available at

https://www.misoenergy.org/Library/Repository/Communication%20Ma

terial/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions

.pdf. 728 SPP, SPP’s Reliability Impact Assessment of the EPA’s 

Proposed Clean Power Plan, (Oct. 8, 2014), available at

http://www.spp.org/publications/CPP%20Reliability%20Analysis%20R

esults%20Final%20Version.pdf. 
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available to them. The Analysis Group recently analyzed 

reliability considerations in MISO as the region considers how 

to comply with the final rule.729 The Analysis Group found that 

despite the large amount of coal that will likely retire in MISO 

in the coming years, the entities responsible for electric 

system reliability in MISO are prepared to collaboratively 

address any reliability issues that arise there is a “strong 

tool kit for managing `Essential Reliability Services‘ needed to 

assure high-quality electric service.”730 

ERCOT also performed an analysis, modelling numerous 

scenarios.731 ERCOT stated that its modelling identified two 

potential reliability problems – impacts of units retiring and 

increased levels of renewable generation on the ERCOT grid.732 As 

 

729 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan: The Case of MISO (June 8, 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/analysis_group_clean_power_plan_miso_reliability.pdf. 

730 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan: The Case of MISO, at 2 (June 8, 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/analysis_group_clean_power_plan_miso_reliability.pdf. 

731 ERCOT, ERCOT Analysis of the Clean Power Plan (Nov. 17, 

2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf. 

732 ERCOT, ERCOT Analysis of the Clean Power Plan, at 9 (Nov. 17, 

2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf.
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noted above, the final rule gives additional time for 

compliance, providing needed time to obtain new or replacement 

generation necessary as some existing generators retire. 

Moreover, affected EGUs needed for reliability should be able to 

employ the flexibilities afforded to them as they seek lower and 

zero-emitting generation. Finally, we note that ERCOT has an 

extremely positive history of integrating renewables into its 

electric grid, giving ERCOT significant expertise regarding 

challenges that may arise with the addition of new renewables in 

order to comply with the final rule. In fact, a recent Brattle 

report used ERCOT as a case study for how to effectively 

integrate a large number of renewables into the electric grid.733 

 PJM conducted its own analysis at the request of the 

Organization of PJM States (OPSI).734 This analysis is consistent 

with many of the M.J. Bradley guiding principles. PJM designed 

various scenarios to capture the impact of the proposed rule 

under a series of assumptions. Because the EPA had not yet 

 

733 Brattle Group, Integrating Renewable Energy Into the 

Electricity Grid: Case Studies Showing How System Operators are 

Maintaining Reliability (June 2015), available at

http://info.aee.net/integrating-renewable-energy-into-theelectricity-grid. 

734 PJM, PJM Interconnection Economic Analysis of the EPA Clean 

Power Plan Proposal (Mar. 2, 2015), report listed at

http://www.pjm.com/documents/reports.aspx. 
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issued the final rule, PJM cautioned against using the report as 

a reliability analysis or predictor of the future. PJM stated 

that, since 2007, PJM’s capacity markets have helped to attract 

35,000 MWs of additional generation. Even though 26,000 MWs will 

retire between 2009 and 2016, the PJM capacity market has 

procured sufficient resources to maintain reliability. 

 WECC also produced a study which is part of a longer-term, 

phased effort.735 The assumptions, methodology, and limitations 

were all clearly presented and there was extensive involvement 

by a range of stakeholders. WECC stated that it is embarking on 

a phased-study process that seeks to “provide the industry with 

unbiased and independent analysis of this issue.”736 WECC 

concluded that the effects of the proposal on resource adequacy 

may be minimal but that resource adequacy cannot be fully 

assessed without realistic and/or proposed compliance 

 

735 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 

736 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report, at 1 (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 
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scenarios.737 

 Analysis Group analyzed the proposed rule, finding that it 

provides states and affected EGUs with a wide range of 

compliance options and operational discretion that can prevent 

reliability issues while also reducing carbon pollution and 

costs.738 The Analysis Group noted that some of the concerns 

raised by stakeholders about the proposed rule assume 

“inflexible implementation, are based upon worst-case scenarios, 

and assume that policy makers, regulators, and market 

participants will stand on the sidelines until it is far too 

late to act” to ensure reliability.739 It stated that these 

assumptions are not consistent with past actions. 

 We appreciate the time that multiple entities took to 

 

737 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report, at 30 (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 

738 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan Tools and Practices (Feb. 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/electric_system_reliability_and_epas_clean_power_plan_too

ls_and_practices.pdf. 

739 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan Tools and Practices, at ES-3 (Feb. 2015), available 

at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/electric_system_reliability_and_epas_clean_power_plan_too

ls_and_practices.pdf.
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analyze and consider the potential impacts of the proposed rule. 

As we issue the final rule and states draft plans to implement 

the rule, we look forward to further analysis by these and other 

groups. Such analysis can provide states with needed resources 

to help them design state plans that will augment the efforts of 

the industry to maintain electric reliability. 

3. Consideration of effects to employment and economic 

development 

States in designing their state plans should consider the 

effects of their plans on employment and overall economic 

development to assure that the opportunities for economic growth 

and jobs that the plans offer are manifest. To the extent 

possible, states should try to assure that any communities that 

can be expected to experience job losses can also take advantage 

of the opportunities for job growth or otherwise transition to 

healthy, sustainable economic growth. The EPA’s illustrative 

analysis 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 may be new jobs in 

the utility power sector associated with both improving the 

efficiency of fossil fuel-fired power plants, construction and 

Commented [A32]: This text seemed quite accurate and 

important—could it be reinstated? 
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operation of new natural gas-fired and renewable power 

production, and actions to increase demand side EE. 

Consideration of these effects in the context of the particulars 

of the state plan can help states craft plans that, to the 

extent possible, meet multiple environmental 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.740 In addition, the 

Department of Commerce, Department of Labor (DOL), Small 

Business Administration, and the Appalachian Regional Commission 

have together created an initiative to issue grants to 

partnerships of regionally-driven economic development and 

workforce development organizations in impacted coal 

communities.741 

4. Workforce considerations 

 

740 http://www.eda.gov/power/. 741 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 
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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 

Some commenters have raised concerns that the emission 

guidelines and requirements for 111(d) state plans violate 

principles of federalism embodied in the U.S. Constitution, 

particularly the Tenth Amendment. These commenters claim that 

states will be unconstitutionally “coerced” or “commandeered” 

into taking certain actions in order to avoid the prospect of 
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either a federal 111(d) plan applying to sources in the state, 

or of losing federal funds. 

 We disagree on both fronts. First, the prospect of a 

federal plan applying to sources in a state does not “coerce” or 

“commandeer” that state into submitting its own satisfactory 

plan. Far from violating principles of federalism, this rule 

provides states with the initial opportunity to submit a 

satisfactory state plan, and provides states flexibility in 

developing that plan. If a state declines to take advantage of 

that opportunity, affected EGUs in that state will instead be 

subject to a federal plan that satisfies statutory 

requirements.742 This approach is consistent with ordinary 

cooperative federalism regimes that federal courts have 

routinely upheld against Tenth Amendment challenges.743 

 

742 Among other things, a federal plan will implement standards 

of performance subject to specific statutory requirements. See 

42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the 

imposition of any federal plan that is “arbitrary, capricious, 

an abuse of discretion, or otherwise not in accordance with 

law.” 5 U.S.C. § 706(2)(a). Particularly given these independent 

constraints on the EPA’s authority with respect to any potential 

federal plan, the prospect of any such plan would not commandeer 

states or coerce them into submitting their own state plans. 

743 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 
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 Second, states that decline to take certain actions under 

this rule will not face the prospect of sanctions, such as 

withdrawn federal highway funds. CAA section 111 does not 

contain sanctions provisions, and we are finalizing revisions to 

these emission guidelines making explicit that the EPA will not 

withhold federal funds from a state on account of that state’s 

failure to submit or implement an approvable 111(d) state plan. 

Some commenters pointed to section 110(m) as a possible 

source of the EPA’s sanction authority.744 Section 110(m) grants 

the EPA discretionary authority to withhold some federal highway 

funds under certain conditions. However, section 110(m) requires 

the EPA to adopt regulations to “establish criteria for 

exercising” this discretionary authority, and the only EPA 

regulations implementing section 110(m) apply to SIPs submitted 

under section 110.745

The EPA never intended to even imply that we would 

contemplate using this authority to encourage state 

 

direct federal administration if a State chooses not to 

administer it”). 

744 Other commenters point to CAA section 179 as a possible 

direct source of this sanctions authority. However, the 

mandatory sanctions outlined in section 179 clearly apply only 

in the contexts of nonattainment SIPs and responses to SIP Calls 

made under CAA section 110(k)(5). See 42 U.S.C. § 7509(a). 745 40 CFR 52.30 (defining “plan or plan item”). 
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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. 

6. Title IV 

 States that are recipients of EPA financial assistance must 

comply with all federal nondiscrimination statutes that together 

prohibit discrimination on the bases of race, color, national 

origin (including limited-English proficiency), disability, sex 

and age. These laws include: Title VI of the Civil Rights Act of 

1964; Section 504 of the Rehabilitation Act of 1973; Section 13 

of the Federal Water Pollution Control Act Amendments of 1972; 

Title IX of the Education Act Amendments of 1972; and the Age 
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Discrimination Act of 1975. Compliance with these 

nondiscrimination statutes is a recipient’s separate and 

distinct obligation from compliance with environmental 

regulations. In other words, all recipients are required to 

ensure that all aspects of their state plans do not violate any 

of the federal nondiscrimination statutes, including Title VI. 

The EPA’s Office of Civil Rights (OCR) is responsible for 

carrying out compliance with these federal nondiscrimination 

statutes and does so through a variety of means including: 

complaint investigation; agency-initiated compliance reviews; 

pre-grant award assurances and audits; and technical assistance 

and outreach activities. Anyone who believes that any of the 

federal nondiscrimination laws enforced by OCR have been 

violated by a recipient of EPA financial assistance may file an 

administrative complaint with EPA’s OCR. 

H. Resources for States to Consider in Developing Plans

 As part of the stakeholder outreach and comment processes, 

the EPA asked states what the agency could do to facilitate 

state plan development and implementation. In addition, after 

the comment period closed, the EPA continued to consult with 

state organizations including the Association of Air Pollution 

Control Agencies (AAPCA), Environmental Council of the States 
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(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. 

This guidance should include allowable programs and policies for 

compliance, examples of compliance pathways, clear information 
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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 

method for use in a state plan. States will need to demonstrate 
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that any measure included in a state plan meets all relevant 

criteria and adequately addresses elements of the plan 

components discussed in section VIII.D of this preamble. 

I. Considerations for CO2 Emission Reduction Measures that Occur 

at Affected EGUs 

 . This section describes a range of emission reduction 

actions that may be taken at affected EGUs that reduce CO2

emissions from an affected EGU and/or improve its CO2 emission 

rate, and the accounting treatment for these actions in a state 

plan. Some of these actions do not necessitate additional 

accounting, monitoring or reporting requirements. Such actions 

are discussed in section VIII.I.1 below, and include heat rate 

improvements, fuel switching from one fossil fuel to another, 

integration of RE into EGU operations, and combined heat and 

power (CHP) expansion or retrofit. Other actions, however, do 

necessitate additional accounting, monitoring, or reporting 

requirements. These include use of CCS, CCU and biomass, as 

discussed in section VIII.I.2 below. 

 The discussion in this section applies for both rate-based 

and mass-based plans. Additional accounting considerations for 

mass-based plans are discussed in section VIII.J. Additional 

accounting considerations for rate-based plans, including how 
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actions that substitute for generation from affected EGUs or 

avoid the need for generation from affected EGUs may be used in 

a state plan to adjust the CO2 emission rate of an affected EGU, 

are discussed in section VIII.K. 

1. Actions without additional accounting and reporting 

requirements 

 Many actions will reduce the reported CO2 emissions or CO2

emission rate of an affected EGU, without the need for 

additional accounting or monitoring and reporting requirements 

beyond the required CEMS tracking of actual stack CO2 emissions 

and tracking of actual energy output.746 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;747 and 

 

746 Monitoring and reporting requirements for affected EGU CO2 

emissions and useful energy output are addressed in section 

VIII.F.

747 “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 
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 CHP, including retrofit of an affected EGU to a CHP 

configuration, or revising the useful energy outputs 

(electrical and thermal) at an affected EGU already 

operating in a CHP configuration.748

 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, and to monitor and report useful energy 

outputs. Stack monitoring would reflect reductions in CO2

emissions from efficiency improvements, changes in fuel use 

(including incorporation of RE), and other on-site changes. 

2. Actions with additional accounting and reporting requirements 

 Certain actions that may be taken at an affected EGU to 

 

feedwater. Such approaches reduce the amount of fossil fuel heat 

input per unit of useful energy output. 

748 The emission reduction potential from CHP stems from the unit 

using less fuel for producing useful electrical and thermal 

outputs than would be required to run separate electrical and 

thermal units. The emission reduction would depend on the type 

of affected EGU and available steam hosts in the vicinity of the 

affected EGU. A conventional combustion turbine generator, for 

example, converted into a CHP unit could effectively result in a 

reduction of 25 percent or more in the reported CO2 emission 

rate. The potential retrofitted EGU CHP market consists of 

converted simple cycle turbines, older steam plants in urban 

areas, and combined cycle units near beneficial thermal loads. 
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reduce CO2 emissions, specifically application of CCS and CCU, 

and use of biomass, require additional accounting and reporting. 

a. Application of CCS. Affected EGUs may utilize retrofit CCS 

technology to reduce reported stack CO2 emissions from the EGU.749

Affected EGUs that apply CCS under a state plan must meet the 

same monitoring, recordkeeping and reporting requirements for 

sequestered CO2 as new units that implement CCS to meet final 

standards of performance under CAA section 111(b) for new 

EGUs.750 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 

 

749 Addition of retrofit CCS technology should not trigger CAA 

section 111(b) applicability for modified or reconstructed 

sources. Pollution control projects do not trigger NSPS 

modifications and addition of CCS technology does not count 

toward the capital costs of reconstruction for NSPS. 

750 Standards of Performance for Greenhouse Gas Emissions from 

New, Modified, and Reconstructed Stationary Sources: Electric 

Utility Generating Units. 
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RR (Geologic Sequestration of Carbon Dioxide).751,752 See 40 CFR 

part 60.46Da(h)(5) and part 60.5555(d). Taken together, these 

requirements ensure that the amount of captured and sequestered 

CO2 will be tracked as appropriate at project- and nationallevels, and that the status of the CO2 in its sequestration site 

will be monitored, including air-side monitoring and reporting. 

As detailed in the preamble for the CAA section 111(b) standards 

for new EGUs, the EPA found that there is ample evidence that 

CCS is technically feasible and that partial CCS can be 

implemented at a new fossil fuel-fired steam generating EGU at a 

cost that is reasonable and that is consistent with the cost of 

other dispatchable, non-NGCC generating options. In the June 

2014 proposal, the EPA noted that CCS technology at existing 

 

751 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. 

752 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. 

Deleted: is convinced
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EGUs would entail additional considerations beyond those at 

issue for newly constructed EGUs. Specifically, the cost of 

integrating a retrofit CCS system into an existing facility may 

be expected to be substantial, and some existing EGUs may have 

space limitations and thus may not be able to accommodate the 

expansion needed to install the equipment to implement CCS. 

Further, the EPA noted that aggregated costs of applying CCS as 

a component of the BSER for the large number of existing fossil 

fuel-fired steam EGUs would be substantial and would be expected 

to affect the cost and potentially the supply of electricity on 

a national basis. Because there are lower-cost systems of 

emission reduction available to reduce emissions from existing 

plants, the EPA did not propose nor finalize CCS as a component 

of the BSER for existing EGUs. 

However, the EPA noted that CCS may be a viable CO2

mitigation technology at some existing sources and that it would 

be available to states and to sources as a compliance option. 

Numerous commenters agreed with the EPA’s proposed determination 

that CCS technology is not part of the BSER building blocks for 

existing EGUs. Other commenters opposed inclusion of CCS 

requirements in state plans and provided specific reasons why 

CCS would not be applicable in certain states. Many commenters 

Deleted: For those reasons
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felt that CCS technology is not adequately demonstrated and is 

not economically practical at this time. Other commenters argued 

that CCS is an available technology and that it can be 

implemented at more EGUs than predicted by EPA modelling. 

Some commenters noted that there are opportunities to 

reduce the cost of CCS implementation by selling the captured CO2

for use in Enhanced Oil Recovery (EOR) operations. One commenter 

expressed concern that federal requirements under the Greenhouse 

Gas Reporting Program – specifically the requirement (mentioned 

above) to report under 40 CFR part 98 subpart RR – would 

foreclose, rather than encourage, the use of captured CO2 for 

EOR. The EPA received similar public comments on the CAA 111(b) 

proposal for new EGUs. The EPA disagrees with the commenters’ 

assertions and addressed those in the preamble for the final 

standards of performance and in the Response-to-Comments (RTC) 

document for the CAA 111(b) NSPS rulemaking. The EPA noted that 

the cost of compliance with subpart RR is not significant enough 

to offset the potential revenue for the EOR operator from the 

sale of produced oil for CCS projects that are reliant on EOR. 

The costs associated with subpart RR are relatively modest, 

especially in comparison with revenues from an EOR field. 

b. Application of CCU. The EPA received comments suggesting that 
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carbon capture and utilization (CCU) technologies should also be 

allowed as a CO2 emission rate adjustment measure for affected 

EGUs. 

Potential alternatives to storing CO2 in geologic formations 

are emerging and these relatively new potential alternatives may 

offer the opportunity to offset the cost of CO2 capture. For 

example, captured anthropogenic CO2 may be stored in solid 

carbonate materials such as precipitated calcium carbonate (PCC) 

or magnesium or calcium carbonate, bauxite residue carbonation, 

and certain types of cement through mineralization. The 

carbonate materials produced can be tailored to optimize 

performance in specific industrial and commercial applications. 

For example, these carbonate materials have been used in the 

construction industry and, more recently and innovatively, in 

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 
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carbonate and sodium bicarbonate.753 Other companies – including 

Calera754 and New Sky755 – also offer commercially available 

technology for the beneficial use of captured CO2. These 

processes can be utilized in a variety of industrial 

applications – including at fossil fuel-fired power plants. 

However, consideration of how these emerging alternatives 

could be used to meet CO2 emission performance rates or state CO2

emission goals would require a better understanding of the 

ultimate fate of the captured CO2 and the degree to which the 

method permanently isolates the captured CO2 or displaces other 

CO2 emissions from the atmosphere. 

Several commenters also suggested that algae-based CCU 

(i.e., the use of algae to convert captured CO2 to useful 

products – especially biofuels) should be recognized for its 

potential to reduce emissions from existing fossil-fueled EGUs. 

Unlike geologic sequestration, there are currently no 

uniform monitoring and reporting mechanisms to demonstrate that 

these alternative end uses of captured CO2 result in overall 

reductions of CO2 emissions to the atmosphere. As these 

alternative technologies are developed, the EPA is committed to 

 

753 http://skyonic.com/technologies/skymine. 754 http://www.calera.com/beneficial-reuse-of-co2/process.html. 755 http://www.newskyenergy.com/index.php/products/carboncycle. 
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working collaboratively with stakeholders to evaluate the 

efficacy of alternative utilization technologies, to address any 

regulatory hurdles, and to develop appropriate monitoring and 

reporting protocols to demonstrate CO2 reductions. 

In the meantime, state plans may allow affected EGUs to use 

qualifying CCU technologies to reduce CO2 emissions that are 

subject to an emission standard, or those that are counted when 

demonstrating achievement of the CO2 emission performance rates 

or a state rate-based or mass-based CO2 emission. State plans 

must include analysis supporting how the proposed qualifying CCU 

technology results in CO2 emission mitigation from the regulated 

sources and provide monitoring, reporting, and verification 

requirements to demonstrate the reductions. The EPA would then 

review the appropriateness and basis for the analysis and the 

verification requirements in the course of its review of the 

state plan. 

c. Biomass co-firing and repowering. 

The EPA received multiple comments supporting the use of 

biomass feedstocks as a means of reducing CO2 emissions within 

state plans. Several commenters also asserted that states should 

be able to determine how biomass can be used in their plans. 

Additionally, the EPA received a range of comments regarding the 
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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 Sources756 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.”757 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 

qualifying biomass feedstocks or feedstock categories in its 

review of a state plan. 

(1) Considerations for use of biomass in state plans. As 

 

756 www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-CO2-Emissions.pdf.

757 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.
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detailed in the President’s Climate Action Plan,758 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 the use of some biomass-derived 

fuels can play a role in controlling or reducing the 

contribution of CO2 emissions to the atmosphere. The EPA also 

anticipates that some states may consider the use of certain 

biomass-derived fuels used in electricity generation as a way to 

control or reduce the contribution of CO2 emissions to the 

atmosphere, and will include them as part of their state plans 

to meet the emission guidelines. 

With regard to assessing qualifying biomass specified in 

 

758 www.whitehouse.gov/sites/default/files/image/ 

president27sclimateactionplan.pdf. 
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state plans, the EPA generally acknowledges the CO2 emissions and 

climate policy benefits of waste-derived biogenic feedstocks759

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 wastederived 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 statesupplied analysis of proposed qualifying feedstocks or feedstock 

categories can adequately demonstrate that such feedstocks or 

feedstock categories appropriately control or reduce CO2

emissions to the atmosphere. 

 

759 Types of waste-derived biogenic feedstocks may include: 

landfill gas generated through the decomposition of MSW in a 

landfill; biogas generated from the decomposition of livestock 

waste, biogenic MSW, and/or other food waste in an anaerobic 

digester; biogas generated through the treatment of waste water, 

due to the anaerobic decomposition of biological materials; 

livestock waste; and the biogenic fraction of MSW at waste-toenergy facilities. 
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Many states have recognized the importance of forests and 

other lands for climate resilience and mitigation, and have 

developed a variety of sustainable forestry policies, RE 

incentives and standards, and GHG accounting procedures. Some 

states, for example Oregon and California, have programs that 

recognize the multiple benefits that forests provide, including 

biodiversity and ecosystem services protection as well as 

climate change mitigation through carbon storage. Oregon has 

several programs focused on best forest management practices and 

sustainability, including the Oregon Indicators of Sustainable 

Forests, that promote environmentally, economically and socially 

sustainable management of state forests. California’s Forest 

Practice Regulations support sustained production of highquality timber while considering ecological, economic and social 

values, and the state’s Greenhouse Gas Reduction Fund provides 

resources for forestry projects to improve forest health, 

maintain carbon storage and avoid GHG emissions from pests, 

wildfires and conversion to non-forest uses. 

Several states focus on sustainable bioenergy, as seen with 

the sustainability requirements for eligible biomass in the 

Massachusetts RPS, which, among other requirements, limits old 

growth forest harvests. Many states employ complementary 
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programs that together work to address sustainable forestry 

practices. For example, Wisconsin uses a state forest 

sustainability framework that provides a common system to 

measure the sustainability of the state’s public and private 

forests, in conjunction with a series of voluntary best 

management guideline manuals for sustainable woody biomass and 

agriculturally-derived biomass. In addition to state-specific 

programs, some states also actively participate in sustainable 

forest management or certification programs through third-party 

entities such as the Sustainable Forestry Initiative (SFI) and 

the Forest Stewardship Council (FSC). For example, in addition 

to other state sustainability programs, New York has certified 

more than 780,000 acres of state forestland to both SFI and 

FSC’s sustainable forest management programs. SFI and FSC have 

certified more than 63 and 35 million acres of forestland across 

the U.S., respectively. 

These examples demonstrate how states already use diverse 

strategies to promote sustainable forestry and agricultural 

management while realizing their unique economic, environmental 

and RE goals. As states evaluate options for meeting the 

emission guidelines, they may consider how the role of wastederived feedstocks as well as sustainably-derived biomass and 
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sustainable forestry and agriculture programs, such as the 

examples highlighted above, may help them control or reduce CO2

emissions to the atmosphere. In addition, the EPA’s work on 

assessing biogenic CO2 emissions from stationary sources may also 

help inform states’ efforts to assess the role of different 

biogenic feedstocks in their plans and broader climate 

strategies. 

 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.760 The EPA is engaging in a second round of 

targeted peer review with the SAB in 2015.761 As part of this 

 

760 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. 

761 www.epa.gov/sab. 
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technical process, and as the EPA and states implement these 

emissions guidelines, the EPA will continue to assess and 

closely monitor overall bioenergy demand and associated 

landscape conditions for changes that might have negative 

impacts on public health or the environment. 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. 

(2)Additional considerations and requirements for biomass fuels. 

Affected EGUs may use qualifying biomass in order to control or 

reduce CO2 emissions that are subject to an emission standard 

requirement, or those that are counted when demonstrating 

achievement of the CO2 emission performance rates or a state 

rate-based or mass-based CO2 emission goal. Not all forms of 

biomass are expected to be approvable as qualified biomass. A 

state can propose the use of biomass feedstocks or categories of 

biomass feedstocks in its plan and the proposed valuation of 

biogenic CO2 emissions. State plans must include analysis 

supporting why the proposed feedstocks or feedstock categories 

should qualify as an approach for controlling or reducing CO2

emission contributions to the atmosphere as well as the proposed 
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valuation of biogenic CO2 emissions (i.e., the proposed portion 

of biogenic CO2 emissions from use of the biomass feedstock that 

would not be counted when demonstrating compliance with an 

emission standard, or when demonstrating achievement of the CO2

emission performance rates or a state rate-based or mass-based 

CO2 emission goal). 

 The proposed use of biomass sourced from within a state in 

its state plan will be presumptively approvable, providing that 

the proposed biomass feedstock is approvable as qualified 

biomass (as described above). States can also propose to allow 

biomass from out-of-state sources and must satisfactorily 

demonstrate why the out-of-state biomass is considered as 

qualifying biomass. This includes providing evidence of how the 

use of that out-of-state biomass is considered appropriate for 

controlling or reducing CO2 emission contributions to the 

atmosphere in the state plan. Section [&&&] describes how state 

plan submittals must specify the requirements and procedures 

that EM&V measures must meet, ensure robust, independent third 

party verification and establish measures to maintain 

transparency, including disclosure of relevant documentation and 

reports. This includes a description of how these requirements 

will be applied to biomass fuels to ensure that all biomass used 
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meets the state plan requirements for qualifying biomass and 

associated biogenic CO2 benefits. 

 As discussed in section &&&, state plan submittals must 

include measures for tracking and auditing performance to ensure 

that biomass used meets the state plan requirements for 

qualifying biomass and associated biogenic CO2 benefits. Section 

VIII.&&&[formerly D] requires that state plan submittals 

describe CO2 emission monitoring, reporting and recordkeeping 

measures. These requirements also apply to proposed state plan 

submissions on qualifying biomass feedstocks, which must include 

specific measures to ensure that biomass-related biogenic CO2

benefits are quantifiable, verifiable, non-duplicative, 

permanent and enforceable, and include specific monitoring, 

reporting and recordkeeping requirements for verifying feedstock 

type, origin and associated biogenic CO2 benefits. 

 The EPA would review the appropriateness and basis for 

proposed qualifying biomass and biomass treatment determinations 

and related accounting, monitoring and reporting measures in the 

course of its review of a state plan. The EPA’s determination 

that a state plan satisfactorily proves that proposed biomass 

fuels qualify as an approach to control or reduce CO2 emission 

contributions to the atmosphere would be based in part on 
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whether the plan submittal demonstrates that proposed state 

measures for qualifying biomass and related biogenic CO2 benefits 

are quantifiable, verifiable, enforceable, non-duplicative and 

permanent. The EPA recognizes that CCS technology (described 

above in section [VIII.&&&.1.a.(2)(a))] could be applied in 

conjunction with the use of qualified biomass. 

 

(2) Biomass co-firing. Affected EGUs may use qualifying biomass 

co-fired with fossil fuels at an affected EGU. As discussed 

above in this section, not all forms of biomass are expected to 

be approvable and states should propose biomass feedstocks and 

treatment of biogenic CO2 emissions in state plans, along with 

supporting analysis on how that biomass qualifies as an approach 

to control or reduce CO2 emission contributions to the 

atmosphere. The EPA will review the appropriateness and basis 

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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 means to 

control or reduce CO2 emission to the atmosphere 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. 

(3) Biomass repowering. Affected EGUs could fully repower to use 

primarily qualifying biomass. The characteristics of affected 

sources, as discussed in Section IV.D., include the use of at 

least 10 percent fossil fuel for applicability of these emission 

guidelines. An EGU repowering with at least 90 percent biomass 

fuels instead of fossil fuels becomes a non-affected EGU.762 An 

 

762 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. 

Commented [A33]: Would this constitute the same problem as 

new gas plants in a mass based state? 
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EGU repowering with less than 90 percent biomass would remain an 

affected EGU and therefore need to propose biomass feedstocks 

and treatment of biogenic CO2 emissions in state plans, along 

with supporting analysis of how that biomass qualifies as an 

approach to control or reduce CO2 emission contributions to the 

atmosphere. 

J. Additional Considerations and Requirements for Mass-Based 

State Plans 

 This section discusses considerations and requirements for 

different types of mass-based state plans. This includes massbased state plans using emission budget trading programs, and 

coordination among such programs where states retain individual 

mass CO2 emission goals. 

1. Accounting for CO2 emission reduction measures in mass-based 

state plans 

As discussed in section VIII.I, measures that occur at 

affected EGUs will result in CO2 emission reductions that are 

automatically accounted for in reported CO2 emissions. Other 

measures that provide substitute generation for affected EGUs or 

avoid the need for generation from affected EGUs, such as 

demand-side EE, are automatically accounted for under a massbased plan to the extent that these measures reduce reported CO2
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emissions from affected EGUs. Unlike under a rate-based plan, no 

additional accounting is necessary in order to recognize these 

emission reductions. 

2. Use of emission budget trading programs 

This section addresses the use of emission budget trading 

programs in a mass-based state plan, including provisions 

required for such programs and the design of such programs in 

the context of a state plan. This includes program design 

approaches that ensure achievement of a state mass-based CO2

emission goal (section VIII.J.2.b), as well as how states can 

use emission budget trading programs with broader source 

coverage and other flexibility features in a state plan, such as 

the programs currently implemented by California and the RGGI 

participating states (section VIII.J.2.c). Section VIII.J.2.d 

addresses other considerations for the design of emission budget 

trading programs that states may want to consider, such as 

allowance allocation approaches. Section VIII.J.3 addresses 

multi-state coordination among emission budget trading programs 

used in states that retain their individual state mass-based CO2

goals. 

a. State plan provisions required for a mass-based emission 

budget trading program approach. For a mass-based emission 
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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. 

b. 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 
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the interim and final plan performance periods. This approach 

would limit total CO2 emissions from affected EGUs during the 

interim and final plan performance periods to an amount equal to 

or less than the state’s mass-based CO2 goal. 

 Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs. No 

further demonstration would be necessary by the state to 

demonstrate that its plan would achieve the state’s mass-based 

CO2 goal. 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal,763 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. 

 

763 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 provisions have been used extensively in rate-based 

environmental programs and mass-based emission budget trading 

programs.764 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.765 It is also beneficial when addressing pollutants that 

are long-lived in the atmosphere, such as CO2, and where 

increasing atmospheric concentration of the pollutant leads to 

increasing adverse atmospheric impacts. 

Banking also provides long-term economic signals to 

affected emission sources and other market participants where 

actions taken today will have economic value in helping meet 

tighter emission constraints in the future, provided those 

emission sources expect that the banked emission rate credits or 

 

Deleted: ¶
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emission allowances may be used for compliance in the future. 

Linking short-term and long-term economic incentives, which 

allows owners or operators of affected EGUs and other market 

participants to assess both short-term and long-term incentives 

when making decisions about compliance approaches or emission 

reduction investments, reduces long-term compliance costs for 

affected EGUs and ratepayer impacts. In addition, the increased 

temporal flexibility provided by banking would further help 

address potential electric reliability concerns, as banked ERCs 

can be used to meet emission standard requirements for an 

affected EGU. 

c. Addressing emission budget trading programs with broader 

source coverage and other flexibility features. 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 massbased emission standards, in the form of an emission budget 
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trading program that differs in design from that outlined in 

section VIII.C.3.b(2)(a) above. However, these types of emission 

budget trading programs must be submitted as a state measure, 

rather than incorporated as federally enforceable emission 

standards, as described below. 

 Such programs could include a number of different design 

elements. This includes broader program scope, where a program 

includes other emission sources beyond affected EGUs subject to 

CAA section 111(d), such as industrial sources. Programs might 

also include design elements that make allowances available in 

addition to the established emission budget. This includes 

project-based offset allowances or credits from GHG emission 

reduction projects outside the covered sector and cost 

containment reserve provisions that make additional allowances 

available at specified allowance prices.766 

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 

 

766 For example, both the California and RGGI programs allow for 

the use of allowances awarded to GHG offset projects to be used 

to meet a specified portion of an affected emission source’s 

compliance obligation. The RGGI program contains a cost 

containment allowance reserve that makes available additional 

allowances up to a certain amount, at specified allowance price 

triggers. 
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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,767 in its state plan submittal, of how 

its plan would achieve the state mass-based CO2 goal. This 

demonstration would include a projection of the total CO2

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 

 

767 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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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.768 

d. Considerations for mass-based emission budget trading 

programs. The EPA notes that while an emission budget trading 

program included in an emission standards plan must be designed 

to achieve a state mass-based CO2 goal, states have wide 

discretion in the design of such programs, provided the emission 

standards included in the plan are quantifiable, verifiable, 

enforceable, non-duplicative, and permanent. 

(1) Allowance allocation. A key example is state discretion in 

the CO2 allowance allocation methods included in the program.769

This includes the methods used to distribute CO2 allowances and 

 

768 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.

769 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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the parties to which allowances are distributed. For example, if 

a state chose, it could include CO2 allowance allocation 

provisions that provide incentives for certain types of 

complementary activities, such as RE generation, that help 

achieve the overall CO2 emission limit for affected EGUs 

established under the program. In addition, a state could use 

its allocation provisions to encourage investments in RE and 

demand-side EE in low-income communities. States could also use 

CO2 allowance allocation provisions to provide incentives for 

early action, such as RE generation or demand-side EE savings 

that occur prior to the beginning of the interim plan 

performance period in 2022. For example, a state could include 

CO2 allowance allocation provisions where CO2 allowances are 

distributed to RE generators based on MWh of RE generation that 

occurs prior to 2022. Such provisions might be addressed through 

a finite set-aside of CO2 allowances that are available for 

allocation under these provisions. 

(2) Facility-level compliance. If a state chose, it could 

evaluate compliance (i.e., allowance true-up) under its emission 

budget trading program at the facility level, rather at the 

individual unit level. Facility-level compliance eases 

implementation compared to unit-level compliance; each facility 
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has a single compliance account in which to hold allowances to 

cover emissions from all its affected EGUs rather than having 

individual unit-level compliance accounts. Fewer accounts makes 

it easier for the designated representatives for compliance 

accounts to manage their allowances. This also eliminates the 

potential for a facility that held sufficient allowances to 

mistakenly hold them in the wrong unit-level compliance 

accounts, which puts the unit out of compliance. The EPA has 

adopted facility-level compliance in the emission budget-trading 

programs it administers, including the Acid Rain Program (70 FR 

25162), Clean Air Interstate Rule (70 FR 25162), and Cross-state 

Air Pollution Rule (76 FR 48208). Under this approach, states 

would still track reported unit-level CO2 emissions – while 

evaluating compliance at the facility level – allowing them to 

track increases and decreases of CO2 emissions at individual 

EGUs. 

3. Multi-state coordination: mass-based emission trading 

programs. 

 An individual state may provide for the use of CO2

allowances issued by another state(s) for compliance with the 

mass-based emission standards in its plan. This type of state 

plan would include regulatory provisions that enable affected 
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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.770 

 Two different implementation approaches could be used to 

create such links. A state could submit a “ready-for-interstatetrading” plan using an EPA-approved tracking system, but the 

plan would not identify links with other states. A state could 

also submit a plan with specified bilateral or multilateral 

links that explicitly identify partner states. 

 Interstate allowance linkages would not affect the 

approvability of each state’s individual plan. However, 

different considerations apply for the approvability of an 

individual plan with such links, based on whether the emission 

budget trading program in the plan applies only to affected EGUs 

 

770 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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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.771 State plans using a 

specified EPA-approved tracking system would be deemed by the 

EPA as ready for interstate linkage upon approval of the state 

plan. No additional EPA approval would be necessary for states 

to link their emission budget trading programs, and affected 

EGUs in those states could engage in interstate trading 

subsequent to EPA plan approval. 

 A state would indicate in its plan submittal that its 

emission budget trading system will use a specified EPA-approved 

tracking system. The state would also indicate in the regulatory 

provisions for its emission budget trading program that it would 

recognize as usable for compliance any emission allowance issued 

 

771 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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by any other state with an EPA-approved state plan that also 

uses the specified EPA-approved tracking system. 

 States could also adopt such a collaborative emission 

trading approach over time (through appropriate state plan 

revisions if the plan is not already structured as ready-forinterstate-trading), without requiring all of the original 

participating states to revise their EPA-approved plans. 

 Under the second implementation approach, a state could 

specify the other states from which it would recognize issued 

emission allowances as usable for compliance with its emission 

budget trading program. The state would indicate in the 

regulatory provisions for its emission budget trading program 

that emission allowances issued in other identified partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how allowances will be tracked from issuance 

through use for compliance, through either a joint tracking 

system, interoperable tracking systems, or EPA-administered 

tracking system. The EPA would assess the design and 

functionality of this tracking system(s) when reviewing 

individual submitted state plans. 

 Under this approach, states could also join such a 

collaborative emission trading approach over time. However, all 
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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.772 

a. Considerations for linked emission budget trading programs. 

For individually submitted plans, interstate emission allowance 

linkages would not affect the approvability of each state’s 

plan. However, approvability of an individual linked plan would 

differ based on the structure of the emission budget trading 

program included in the plan. These differences for plan 

approvability address distinctions among programs that include 

only affected EGUs and programs that cover a broader set of 

emission sources. Differences in approval criteria are necessary 

to ensure that each individual state plan demonstrates it will 

achieve a state’s mass-based CO2 emission goal for affected EGUs. 

The accounting applied to individual plans to assess whether a 

 

772 Depending on the specific regulatory provisions in the 

emission standards in their approved state plans, participating 

states may also need to revise their implementing regulations 

(and by extension their state plans) to accept CO2 emission 

allowances issued by new partner states as usable for compliance 

with their mass-based emission standards. 
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state 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. 

(1) 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 massbased emission standard in each plan is equal to or lower than 
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the state’s mass-based CO2 goal, compliance by affected EGUs with 

the mass emission standard in a state773 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.774

 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 

 

773 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. 774 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 state that are 

below that state’s mass CO2 goal. 
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reported CO2 emissions from affected EGUs. 

(2) 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.775 

 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.776 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 

 

775 This may apply under both an emission standards plan and a 

state measures plan. 

776 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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applicable mass-based CO2 goal. 

 During plan implementation, the EPA would assess whether 

the affected EGUs in a state achieved the state’s mass-based CO2

goal as follows. Reported CO2 emissions from affected EGUs under 

such plans must be at or below a state’s mass-based CO2 emission 

goal during an identified plan performance period, with the 

following state accounting adjustments for net “import” and net 

“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.777 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 

 

777 Net “imports” and “exports” of CO2 allowances are defined and 

explained below. 
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affected EGUs in a state during an identified plan 

performance period must be equal to or less than the CO2

mass goal minus an adjustment for the “exported” CO2

allowances during the plan performance period. The 

adjustment represents CO2 emissions (in tons) equal to the 

number of net “exported” CO2 allowances. Net “exports” of 

allowances are determined through review of tracking system 

compliance accounts. 

 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 
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accounts of affected EGUs in another state.778 This net transfer 

is determined based on compliance account holdings at the end of 

the plan performance period.779 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 

 

778 A net transfer metric is applied as of the end of the plan 

performance period. This net accounting as of a specified date 

is necessary because multiple individual allowance transfers may 

occur among accounts during a plan performance period, 

representing normal trading activity. In addition, net transfers 

are based on compliance account holdings, because these 

represent the CO2 allowances directly available at that point in 

time for use by an affected EGU for complying with its emission 

limit. Emission budget trading programs typically allow nonaffected entities to hold allowances in general accounts. These 

parties are free to hold and trade CO2 allowances, providing 

market liquidity. General account holdings are not assessed as 

part of a periodic state net transfer accounting, as these 

allowances may subsequently be transferred to other accounts in 

multiple states and do not represent allowances currently held 

by an affected EGU that can be used for complying with its 

emission limit. 

779 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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example, a net transfer of 500 CO2 allowances has occurred 

between State A and State B. State A has “exported” 500 CO2

allowances to State B, while State B has “imported” 500 CO2

allowances from state A. 

K. Additional Considerations and Requirements for Rate-Based 

State Plans 

 This section discusses considerations and requirements for 

rate-based state plans. This section discusses eligibility, 

accounting, and quantification and verification requirements 

(EM&V) for the use of CO2 emission reduction measures that 

provide substitute generation for affected EGUs or avoid the 

need for generation from affected EGUs in rate-based state 

plans. These measures may be used to adjust the CO2 emission rate 

of an affected EGU under a rate-based state plan. This 

adjustment may occur when an affected EGU is demonstrating 

compliance with a rate-based emission standard, or when a state 

is demonstrating achievement of the CO2 emission performance 

rates or applicable rate-based state CO2 emission goal in the 

emission guidelines.780 This section also discusses requirements 

 

780 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 rate-based state CO2 emission 

goal in the emission guidelines. 
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for state plans that include rate-based emission trading 

programs, including approaches and requirements for coordination 

among such programs where states retain individual state ratebased CO2 emission goals. 

1. Adjustments to CO2 emission rates in rate-based state plans 

Section VIII.K.2.a below describes the basic accounting 

method for adjusting a CO2 emission rate, as well as eligibility 

requirements for measures that may be used for adjusting a CO2

emission rate. Section VIII.K.2.b addresses measures that may 

not be used to adjust the CO2 emission rate of an affected EGU in 

a state plan, and explains the basis for this exclusion. Section 

VIII.K.2.c addresses measures that reduce CO2 emissions outside 

the electric power sector. Such measures may not be counted 

under either a rate-based or mass-based state plan. 

a. 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 
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rate. Where relevant, this section also discusses additional 

specific accounting methods and other relevant requirements that 

apply to different categories of measures. 

A CO2 emission rate adjustment may be applied in different 

rate-based state plan contexts. For example, in a rate-based 

emission trading program, adjustments may be applied through the 

use of ERCs.781 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 

 

781 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. 

Formatted: Highlight
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generation from affected EGUs, thereby reducing CO2 emissions. 

This includes RE measures included in the EPA’s determination of 

the BSER, as well as other measures that were not included in 

the determination of the BSER, such as other RE resources, 

demand-side EE, CHP, WHP, electricity transmission and 

distribution improvements, nuclear energy, and international 

renewable 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.782 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, 

 

782 These requirements are discussed in section VIII.D. 
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through the use of measures that substitute for or avoid 

generation from affected EGUs. That method is based on adding 

MWh from such measures to the denominator of an affected EGU’s 

reported CO2 emission rate (lb CO2/MWh). Those additional MWh are 

based on quantified and verified electricity generation or 

electricity savings from eligible measures, and in the case of 

an affected EGUs compliance with its emission standard, are 

reflected in ERCs. This section also addresses eligibility 

requirements for resources that are used to adjust an affected 

EGU’s CO2 emission rate. 

(1) General accounting approach for adjusting a CO2 emission 

rate. In this final rule, the reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified 

MWh from qualifying zero-emitting and low-emitting resources, as 

described in sections VIII.K.1.a.(2)-(10) below. These MWh are 

added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower adjusted CO2 emission rate. 

 The measures described in these sections reduce mass CO2

emissions from affected EGUs by substituting zero- or lowemitting generation for generation from affected EGUs, or by 

avoiding the need for generation altogether (in the case of 

resources that lower electricity demand through improved demand-
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side 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 at the affected EGU, the fact that both CO2 emissions 

and MWh generation are reduced means that such impacts do not 

alter the reported CO2 emission rate of the affected EGU. As a 

result, the MWh of replacement generation must be added to the 

denominator of the reported CO2 emission rate, in order to 

represent those impacts in the form of an adjusted CO2 emission 

rate. In this manner, adding MWh from these resources to the 

denominator of an affected EGU CO2 emission rate allows mass CO2

emission reductions from these measures to be fully reflected in 

an adjusted CO2 emission rate. 

 The following provides a simple calculation example of how 

MWh of replacement generation added to the denominator of an 

affected EGU’s reported CO2 emission rate results in a lower 

adjusted CO2 emission rate. Assume an affected EGU with CO2
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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.783 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.784 In the case of a state 

measures plan, quantified and verified MWh from eligible state 

measures could be 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 

 

783 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. 

784 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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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 MWhs of RE are reflected in two 

adjustments of the rate: a reduction of CO2 emissions from 

affected EGUs in the numerator and a one-to-one replacement of 

affected EGU generation in the denominator, where it is assumed 

that replaced generation from an affected EGU is subtracted from 

the denominator and the same number of zero-emitting MWh are 

added.785 

 When demonstrating achievement of a CO2 emission performance 

 

785 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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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. Thus, the 

resultant rate, where the numerator reflects CO2 emission 

reductions from qualifying measures, and the denominator 

reflects replaced generation, is consistent with the goalsetting calculation. 

Several commenters suggested that the EPA consider the 

regional nature of the electricity grid and how RE and demandside EE impacts generation and CO2 emissions across the grid when 

accounting for the impacts of RE and demand-side EE measures in 

a rate-based plan approach. This MWh accounting structure 

corresponds with the regional treatment of RE resources in the 

BSER that provide substitute generation in the EPA-calculated CO2
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emission performance rates in the emission guidelines. 

Consistent with assumptions used in calculating the CO2 emission 

performance rates in the emission guidelines, affected EGUs and 

states can take full credit for the MWh resulting from eligible 

measures they are responsible for deploying, no matter where 

those measures are implemented. CO2 emission reductions from the 

eligible measures may occur across the region; however, an 

affected EGU or a state may only take credit for avoided CO2

emissions at that affected EGU or set of EGUs in question, as 

reflected in the reported stack CO2 emissions of affected EGUs. 

Because of the separate accounting of MWhs and CO2

emissions, with emission impacts inherent in reported stack CO2

emissions and zero-emitting MWh impacts requiring explicit 

adjustments, the accounting method corresponds with the use of 

MWh-denominated ERCs in the rate-based emission trading 

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 
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avoided CO2 emissions. 

The MWh accounting method also creates a crediting system 

or rate adjustment process that is indifferent to the rate-based 

CO2 emission goals of individual states, or the specific CO2

emission rate standards that states may apply, and the relative 

stringency of those goals or standards. Use of ERCs in ratebased emission trading programs is addressed in detail in 

section VIII.G.3. As a result, the MWh accounting method 

addresses interstate effects, because it inherently accounts for 

how generation replacement and CO2 emission reduction impacts may 

cross state borders. For example, if the accounting method was 

informed by avoided CO2 emission rates, it could create perverse 

incentives for development of zero- or low-emitting resources in 

states that result in the greatest calculated estimate of CO2

emission reductions for each replacement MWh. Instead, this 

accounting method is indifferent to avoided CO2 emission rates 

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 
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adjust a CO2 emission rate. The EPA is finalizing certain general 

eligibility requirements for resources used to adjust a CO2

emission rate. These requirements align eligibility with certain 

factors and assumptions used in establishing the BSER, and by 

extension, application of the BSER to the performance levels 

established for affected EGUs in the emission guidelines, as 

well as state rate and mass CO2 goals. As a result, the 

requirements ensure that measures that may be used in a state 

plan are treated consistently (to the extent possible) with the 

EPA’s assessment of the BSER.786 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 

 

786 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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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. 

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.787 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 

 

787 For demand-side EE, this eligibility date may require special 

considerations for EM&V plans. EM&V requirements are addressed 

in subsection VIII.C.3. 
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years, without limitation.788 These MWh may be banked from the 

interim to final periods. 

In order to provide additional incentives for early 

investment in RE and demand-side EE, the EPA is also 

establishing a clean energy investment pool, as discussed in 

section VIII.B.2. ERCS distributed from the investment pool may 

also be used by affected EGUs to demonstrate compliance with an 

emission standard, and may be banked from the interim to final 

periods. 

(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. This 2012 date applies consistent eligibility requirements 

to all eligible measures that are used to adjust a CO2 emission 

rate under a state plan. For example, eligible measures, such as 

CHP, nuclear power and DSM, also must be installed after 2012. 

As described above, only the MWh of energy savings that occur in 

2022 and subsequent years as a result of these measures may be 

 

788 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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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 

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
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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 CO2 emission performance rates 

or state goal applied to affected EGUs in their state. For 

example, a steam generating unit that has already reduced its CO2

emission rate through a heat rate improvement may have a CO2

emission rate of 2,000 lb/MWh whereas its rate was 2,100 lb/MWh 

prior to the improvement. Therefore, it has less distance to 

cover to meet its CO2 emission performance rate. 

Second, generation from existing RE capacity installed 

prior to 2013 has been excluded from the EPA’s calculation of 

the CO2 emission performances rates in the emission guidelines. 

That RE generating capacity will still provide zero-emitting 

generation to the grid and will better position states and 
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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, which 

seemed to be an implicit requirement to take action prior to the 

performance period. Because demand-side EE is not used in 

calculating the CO2 emission performance rates in the final 

emission guidelines, this is no longer a concern. Furthermore, 

eligible demand-side EE actions that occur after 2012 can be 

applied toward adjusting the CO2 emission rates of affected EGUs, 

providing a significant compliance option that is not assumed in 

emission performance rates or state goals. 

(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 location that is connected 

to the electricity grid. EE measures only avoid electric 

generation from grid-connected EGUs if the electrical loads 

Commented [A34]: It would be helpful to explain this more 

fully, as it will be a topic of intense focus
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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,789 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.790 This approach is generally consistent with the 

 

789 As used here, a measure is “tied to a state plan” if it is 

issued an ERC under approved procedures in a rate-based emission 

standards plan represents quantified and verified MWh energy 

generation or energy savings achieved by an approved state 

measure in a state measures plan. 

790 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. It also 

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 a 

demonstration that a state plan does not allow recognition of a 

 

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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MWh, for use in adjusting the CO2 emission rate of an affected 

EGU, if the MWh is being or has been used for such a purpose 

under another state plan. Discussion of how such a demonstration 

can be made in the context of a rate-based emission trading 

program is in section VIII.D. 

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 
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existing RE capacity constructed prior to 2012 from the building 

block. The result of these changes is that the RE incorporated 

in the BSER is more equally shared across states. 

(i) Measures that occur in states with mass-based plans. As 

discussed above, eligible measures for adjusting the CO2 emission 

rate of an affected EGU may occur in any state, with certain 

conditions. This includes eligible measures that occur in a 

state with an EPA-approved plan that is meeting a state massbased CO2 goal. However, eligible measures that could be used to 

adjust a CO2 emission rate under a state plan which are located 

in a state with a mass-based plan are restricted from being 

counted under another state’s rate-based plan. An exception is 

made for RE measures that occur in such mass-based states. RE 

measures 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 
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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.791 Since they are not 

counted in the mass-based demonstration, eligible measures 

located in mass-based states could be used in a state with a 

rate-based plan to adjust the CO2 emission rate of affected EGUs. 

Such adjustments would obviate the need for comparable CO2

emission reductions at affected EGUs in the rate-based state or 

the use of other measures to make a rate adjustment. In this 

scenario, to the extent that eligible measures substitute solely 

for generation from affected EGUs in a state with mass-based 

emission limits, and are also used to adjust the reported CO2

emission rate of affected EGUs in a rate-based state, no 

incremental CO2 emissions reductions would occur in the ratebased state as a result of the eligible measures.792 The result 

would be a loss in net CO2 emission reductions that would 

otherwise occur across the two states. These dynamics are 

 

791 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. 792 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. 
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further addressed in section VIII.L. 

 For RE measures located in a mass-based state to have some 

or all of its generation counted under a rate-based plan in 

another state, it must be demonstrated that the generation was 

delivered to the grid to meet electricity load in a state with a 

rate-based plan.793 Some examples of documentation that can serve 

as a demonstration include a power delivery contract or power 

purchase agreement. The EPA is giving states flexibility 

regarding the nature of this demonstration, but a state plan 

must describe the nature of the required demonstration and have 

it be approved by the EPA. 

 Under an emission standards plan, this demonstration must 

be made by the provider of the measure seeking ERC issuance 

under the rate-based emission standards in a rate-based state, 

as part of the eligibility application for the measure.794 The 

rate-based state must include in its state plan provisions that 

describe a sufficient demonstration of geographic eligibility 

for zero- or low-emitting generation under rate-based emission 

standards, or geographic eligibility of state measures that may 

 

793 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. 

794 Requirements for ERC issuance are addressed in subsection 

VIII.C.2. 

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be used to adjust the reported CO2 emission rate of affected 

EGUs.

 Further examples of eligible demonstrations and how they 

should be outlined in state plans is provided in section VIII.L. 

(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 

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stated that because of the integrated nature of the U.S. 

electricity grid, it is appropriate to allow all jurisdictions 

with the ability to contribute to and benefit from CO2 emission 

reductions or CO2 emission rate adjustments. 

For rate-based states and territories, they must adhere to 

EM&V standards, installation dates, and any other criteria that 

apply to all states. Section VIII.K.3 below identifies and 

discusses the EM&V requirements used to quantify MWh savings 

from generation from zero-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 meet 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. 

(iii) Measures that occur outside the U.S. The EPA will work 

with states using the rate-based approach that are interested in 

allowing the use of RE from outside the U.S. to adjust CO2

emission rates. In these cases, all conditions for creditable 

domestic RE must be met, including that RE resources must be 

incremental and installed after 2012, and all EM&V standards 
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must be met. In addition, the country generating the ERCs must 

be connected to the U.S. grid, and there must be a power 

purchase agreement or other contract for delivery of the power 

with an entity in the U.S. RE generation capacity outside the 

U.S. that existed prior to 2012 but was not exported to the U.S. 

is not considered new or incremental generation and, therefore, 

not eligible for adjusting CO2 emission rates under this rule. 

For example, a new transmission interconnection to existing RE 

in Canada would not be considered incremental, but a new 

interconnection to RE where the RE was built after 2012 would be 

considered incremental. See below for more specifics regarding 

the use of incremental hydroelectric power in a rate-based 

approach. 

 The EPA received comments encouraging the use of 

international zero-emitting electricity imports in state plans, 

particularly hydroelectric power from Canada. Canada currently 

provides states such as Minnesota and Wisconsin with RE through 

existing grid connections. New projects are in various stages of 

development to increase generating capacity, which could be 

called upon as a base load resource to supplement variable forms 

of RE generation. Commenters said that the EPA should permit the 

use of all incremental hydropower—both domestic and 
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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. RE795, demand-side EE and other 

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.796 

 In addition, a capacity uprate at an existing RE facility 

(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. 

Quantification and accounting criteria for incremental RE and 

nuclear generation are provided in section VIII.G.5. 

Many commenters supported using RE deployment as measures 

 

795 As used in this section, RE includes electric generating 

technologies using RE resources, such as wind, solar, 

geothermal, hydropower, qualifying biomass and wave and tidal 

power. 

796 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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to adjust the CO2 emission rate of affected EGUs. Some commenters 

specifically agreed with the EPA’s determination that only new 

and incremental RE (including hydropower) should be used to 

adjust CO2 emission rates. Those commenters objected to counting 

existing RE that are already embedded in the baseline emissions 

and generation mix. A significant number of commenters supported 

the integration of RE into a rate-based credit trading system. 

 Certain additional requirements apply for hydropower and 

biomass (including waste-to-energy) RE, as described below. 

(a) Hydroelectric power. Consistent with other types of RE, new 

hydroelectric power generating capacity installed after 2012 is 

eligible for use in adjusting a CO2 emission rate. 

 Relicensed facilities are considered existing capacity and, 

therefore, are not eligible for use in adjusting a CO2 emission 

rate, unless there is a capacity uprate as part of the 

relicensed permit. In such a case, only the incremental capacity 

is eligible for use in adjusting a CO2 emission rate. 

 The EPA noted that many commenters preferred that 

generation from hydropower displace generation from fossil 

sources. One commenter suggested that existing zero-emitting 

sources, including hydropower, do not reduce emissions from 

existing fossil generation, but that new or uprated zero-
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emitting sources would, because of their low variable rate, 

reduce fossil emissions. Several commenters recommended allowing 

incremental generation from new or uprated zero-emitting 

sources, including hydropower, be available for compliance. One 

commenter recognized the difficulty of quantifying emission 

reductions due to uprated zero-emitting sources. The EPA agrees 

that new or updated zero-emitting sources would reduce fossil 

emissions because of their low variable rate and believes the 

approach described is appropriate because prorating hydropower 

generation based on the percentage increase in capacity is 

accurate and credible. 

(b) Biomass. RE generating capacity installed after 2012 that 

uses qualifying biomass as a fuel source is eligible for use in 

adjusting a CO2 emission rate.797 As discussed in section 

VIII.&&&.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 

 

797 As with other RE, only generating capacity installed after 

2012 would be eligible for use in adjusting a CO2 emission rate. 
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designated in an approved state plan, MWh generation from the 

unit could be used to adjust a CO2 emission rate. Considerations 

for the use of biomass in state plans are discussed in section 

VIII.&&&.1.a(2)(c)(i). 

(c) Waste-to-energy. Qualifying biomass may include the biogenic 

portion of MSW combusted in a waste-to-energy facility.798 With 

regard to assessing qualifying biomass proposed in state plans, 

the EPA generally acknowledges the CO2 emissions and climate 

policy benefits of waste-derived biomass, which includes 

biogenic MSW inputs to waste-to-energy facilities. The process 

and considerations for the use of biomass in state plans are 

discussed in section VIII.I.2.c. 

 MSW can be directly combusted in waste-to-energy facilities 

to generate electricity as an alternative to landfill disposal. 

In the U.S., almost all incineration of MSW occurs at waste-toenergy facilities or industrial facilities where the waste is 

combusted and energy is recovered.799 Total MSW generation in 

2012 was 251 million tons, but of that total volume generated, 

 

798 As with other RE, only generating capacity installed after 

2012 would be eligible for use in adjusting a CO2 emission rate. 799 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. 

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

html. 
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almost 87 million tons were recycled and composted.800 Increasing 

demand for electricity generated from waste-to-energy facilities 

could increase competition for and generation of waste stream 

materials - including discarded organic waste materials – which 

could work against programs promoting waste reduction or cause 

diversion of these materials from existing or future efforts 

promoting composting and recycling. The EPA and many states have 

recognized the importance of integrated waste materials 

management strategies that emphasize a hierarchy of waste 

prevention, starting with waste reduction programs as the 

highest priority and then focusing on all other productive uses 

of waste materials to reduce the volume of disposed waste 

materials.801 For example, Oregon and Vermont have strategies 

that emphasize waste prevention, followed by reuse, then 

recycling and composting materials prior to treatment and 

disposal.802 

Information in the revised Framework for Assessing Biogenic 

CO2 Emissions from Stationary Sources and other technical studies 

 

800 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf. 801 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm. 802

http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

. 
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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.803 

 When developing their plans, states planning to use wasteto-energy as an option for the adjustment of a CO2 emission rate 

should assess both their capacity to strengthen existing or 

implement new waste reduction, reuse, recycling and composting 

programs, and measures to minimize any potential negative 

impacts of waste-to-energy operations on such programs. States 

must include that information in their plan submissions. EPA 

[will/may] reject as qualified biomass any proposed waste-toenergy component of state plans if states do not include 

information on their efforts to strengthen existing or implement 

new waste reduction as well as reuse, recycling and composting 

programs, and measures to minimize any potential negative 

impacts of waste-to-energy operations on such programs. Only 

electric generation at a waste-to-energy facility that is 

related to the biogenic fraction of MSW and that is added after 

2012 is eligible for use in adjusting a CO2 emission rate. 

Quantification and accounting criteria for MSW generation are 

 

803 http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html. 
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provided in section VIII.G.5. 

The EPA received multiple comments supporting the use of 

waste-to-energy as part of state plans. Some commenters 

expressed concern that non-biogenic materials, such as plastics 

and metal, would be incinerated along with biogenic materials. 

As discussed above, only electric generation related to the 

biogenic fraction of MSW at a waste-to-energy facility added 

after 2012 is eligible for use in adjusting a CO2 emission rate. 

The EPA also received comments that expressed concern about the 

potential negative impacts on recycling and waste reduction 

efforts, while other commenters asserted that waste-to-energy 

practices encourage recycling programs. Some commenters also 

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 that result from demandside management may be used to adjust a CO2 emission rate. 

Eligible DSM actions are those that are non-emitting and avoid, 

rather than shift, the use of electricity by an electricity end-
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user.804 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. 

(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.805 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.806 However, 

 

804 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. 

805 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). 

806 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 
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energy storage can be used as an enabling measure that 

facilitates greater use of RE, which can be used to adjust a CO2

emission rate. For example, utility scale energy storage may be 

used to facilitate greater grid penetration of RE generating 

capacity and can also be used to store RE generation that may 

have otherwise been shed in times of excess generating capacity. 

Likewise, on-site energy storage at an electricity end-user can 

enable greater use of RE to meet on-site electricity demand.807 

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 

 

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. 

807 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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supporting role in providing zero-emission MWh to the grid 

(consistent with the EPA’s decision to exclude energy storage as 

an eligible measure that can be used to adjust a CO2 emission 

rate). 

(6) Transmission and distribution measures. Electricity T&D 

measures that improve the efficiency of the T&D system and/or 

reduce electricity use may be used to adjust a CO2 emission rate. 

This includes T&D measures that reduce losses of electricity 

during delivery from a generator to an end-user (sometimes 

referred to as “line losses”808) and T&D measures that reduce 

electricity use at the end-user, such as conservation voltage 

reduction (CVR).809 The EPA received many comments in support of 

 

808 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. 

809 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 
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advanced energy technologies, including energy storage and 

transmission and distribution upgrades, and including these 

technologies in the suite of potential measures that states 

could consider for emission rate adjustments in their state 

plans. Comments pointed out that in addition to helping achieve 

emission standards, T&D efficiency improvements make the grid 

more robust and flexible, as well as delivering environmental 

benefits. In many parts of the country, grid operators, 

transmission planners, transmission owners and regulators are 

already taking steps to expand and modernize T&D networks. 

Commenters suggested that the EPA clarify the eligibility and 

criteria under which such measures would be permitted in a state 

plan. 

To be eligible, T&D measures must be 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 

 

voltage reduction (CVR), which are actions taken to reduce 

initial delivered voltage levels in feeder transmission lines 

while remaining within the 114 volt to 126 volt range (for 

normal 120-volt service) required at the customer meter, per the 

ANSI C84.1 standards. 
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VIII.K.3G.5. 

(7) Water system efficiency. Water efficiency programs that 

improve EE at water and wastewater treatment facilities also 

provide demand-side EE savings opportunities. The EPA received 

comments supporting the use of water sector EE programs and 

projects. Commenters identified water and wastewater utilities 

as particularly well-suited for participating in EE programs and 

providing a source of electricity savings. Investments such as 

replacing pumps and other aging equipment and repairing leaks 

can result in greater EE. The EPA agrees that these electricity 

savings should be eligible for adjustments to CO2 emission rates 

at affected EGUs. 

To be eligible, water efficiency measures must be 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 has not included 

nuclear generation from either existing or under construction 

units in the determination of the BSER. In addition to comments 
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received on the provisions for determining the BSER, the EPA 

also received comments requesting that the EPA allow all 

generation from nuclear generating units to be recognized as an 

eligible measure that can be used to adjust a CO2 emission rate. 

Commenters also recommended that the EPA consider nuclear 

generating units and RE generating units in a consistent manner 

for CO2 emission rate adjustments in state plans. We agree with 

comments that nuclear generation and RE should be treated 

consistently when it comes to CO2 emission rate adjustments. 

The EPA has determined that generation from new nuclear 

units and capacity uprates at existing nuclear units will be 

eligible for use in adjusting a CO2 emission rate, just like new 

and increased capacity RE. However, consistent with the reasons 

discussed for not including the preservation of existing nuclear 

capacity in the BSER – namely, that such preservation does not 

actually reduce existing levels of CO2 emissions from affected 

EGUs – preserving generation from existing nuclear capacity is 

not eligible for use in adjusting a CO2 emission rate. 

In contrast, any incremental zero-emitting generation from 

new nuclear capacity would be expected to replace generation 

from affected EGUs and, thereby, reduce CO2 emissions; and the 

continued commitment of the owner/operators to completion of the 
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new units and improving the efficiency of existing units through 

uprates can play a key role in state plans. Therefore, 

consistent with treatment of other low- and zero-emitting 

generation, new nuclear power generating capacity installed 

after 2012 and incremental generation resulting from nuclear 

uprates after 2012 are measures eligible for adjusting a CO2

emission rate. However, existing nuclear units (i.e., those that 

originally commenced operation in 2012 or earlier years) that 

receive operating license extensions are not eligible for use in 

adjusting a CO2 emission rate, except where such units receive a 

capacity uprate as a result of the relicensing process. Only the 

incremental capacity from the uprate is eligible for use to 

adjust a CO2 emission rate. 

(9) Combined heat and power (CHP)units. Electric generation from 

non-affected CHP units810 may be used to adjust the CO2 emission 

 

810 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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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 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. The EPA has proposed the equivalence 

accounting method that accounts for the electrical and thermal 

outputs from affected CHP units. Under the final rule, affected 

units’ total emission rates are required to be accounted and 

ERCs are based on this total emission rate. The equivalence 

method provides a consistent way to account for all types of 

affected CHP units. By this method, a CHP unit’s measured 

electrical and all of its thermal output are factored into the 

unit’s adjusted emission rate. As the affected units are 

electrical generators, a unit’s thermal output is converted to 

an MWh units of measurement (using a uniform conversion method) 

and added to the measured electrical output to determine the 

total useful outputs from the CHP unit. 

The EPA has proposed the avoided emissions method to calculate 

ERCs generated from non-affected CHP units. There are a wide 

range of CHP types that fall in the non-affected unit category 
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and by using this method, the thermal output that will be 

discounted will closely mirror the type of boiler displaced by 

the CHP unit. The avoided emissions approach adjusts the 

electricity emission rate for the CHP unit by subtracting a 

counterfactual on-site boiler emissions from the CHP unit’s 

total emissions. The method adjusts for the efficiency of the 

counterfactual boiler and also ensures that the CHP units only 

get credit to the extent that their emission rates are below the 

reference emission rate. Both approaches are commonly used 

approaches and have been factored in other EPA rules. Both the 

approaches have also been considered in state rules. The 

applicable requirements related to quantification and accounting 

requirements for CHP are provided in section VIII.G.5. 

Non-affected CHP units can use qualifying biomass fuels. 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 

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), while quantification and accounting 
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requirements are provided 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. Commenters described the reductions achieved through CHP’s 

efficiency and the precedent set in other federal and state 

rules that have included CHP as a compliance option. Some 

commenters pointed out that without such a description, states 

would not be able to readily take advantage of the CO2 emissions 

reduced by the use of CHP. Many commenters responded to the need 

for accounting for all of CHP’s thermal output (100%) instead of 

a portion (75%) under an affected unit’s compliance 

requirements. Other commenters weighed the advantages to 

considering a numerator-based approach versus a denominatorbased approach. The EPA believes that a denominator approach is 

appropriate for non-affected CHP units because it is consistent 

with the accounting approach used for RE and demand-side EE and 

reflects that MWh are being generated by lower-emitting 

generation, thus reducing CO2 emissions associated with 

electricity generation. 

(10) Waste Heat Power (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 
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WHP units. There are units, also referred to as bottoming cycle 

CHP units, where the fuel is first used to provide thermal 

energy for an industrial process and the waste heat from that 

process is then used to generate electricity.811 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 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. 

 WHP facilities will be accounted for by the same approach 

(described in the previous section) laid out for non-affected 

CHP units when there are emissions from the WHP process. 

 

811 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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 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 

method. 

b. Measures that may not be used to adjust a CO2 emission rate. 

This section addresses measures that may not be used to adjust a 

CO2 emission rate. New, modified, and reconstructed EGUs covered 

under the CAA section 111(b) final Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units rule are not approvable sources of 

electric generation for adjusting the CO2 emission rate of an 

affected EGU under a rate-based state plan. As discussed earlier 

in section VII.C of this preamble, a key concern under this rule 

is leakage to new units that are not covered by the emission 

guidelines. Emissions leakage, or increased CO2 emissions due to 

increase utilization of unaffected sources, is contradictory to 

objectives of this rule and should, therefore, be minimized. 

Allowing affected EGUs to adjust their emission rates as a 

result of lower-emitting new NGCC units not covered under this 

section 111(d) rule would not mitigate leakage concerns, and 
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could even exacerbate the situation. Consequently, new EGUs 

covered under the 111(b) rule are not allowable measures in 

state plans because the EPA believes it would result in 

increased emission leakage. The EPA received comments both 

supporting and opposing the use of new NGCC units in state 

plans. Some comments expressed concerns that emissions from new 

NGCC units displacing generation from existing EGUs would not be 

taken into account. The EPA is also concerned about emission 

leakage and has addressed it for mass-based state plans (see 

preamble section VIII.C) and is not allowing it as a state plan 

measure for rate-based plans. 

In addition, other new and existing non-affected fossil 

fuel-fired EGUs that are not subject to CAA section 111(b) or 

111(d), such as simple cycle combustion turbines, may not be 

used to adjust the CO2 emission rate of an affected EGU. While 

generation from such units could substitute for generation from 

affected EGUs, the EPA has determined that additional incentives 

for such generation, in the form of an explicit adjustment to 

the CO2 rate of an affected EGU, are not necessary or warranted. 

Providing for such an adjustment could create perverse 

incentives for the construction of new simple cycle CTs that are 

not subject to the applicability criteria of final Standards of 
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Performance for Greenhouse Gas Emissions from New Stationary 

Sources: Electric Utility Generating Units rule. These units 

could provide only limited adjustment credit, as operation 

beyond a certain capacity factor threshold would trigger 

applicability under CAA section 111(b). Further, providing for 

the ability to generate adjustment credits would provide 

incentives for construction of less efficient fossil generating 

capacity than would likely otherwise be constructed (e.g., 

addition of a simple cycle combustion turbine rather than a NGCC 

unit). In addition, providing for the ability to generate 

adjustment credits could create perverse incentives for the 

continued operation of less efficient existing fossil generating 

capacity. Such outcomes run counter to the objectives of this 

final rule. 

c. Measures that reduce CO2 emissions outside the electric power 

sector. Measures that reduce CO2 emissions outside the electric 

power sector may not be counted toward meeting a CO2 emission 

performance level for affected EGUs or a state CO2 goal, under 

either a rate-based or mass-based approach, because all of the 

emission reduction measures included in the EPA’s determination 

of the BSER reduce CO2 emissions from affected EGUs. Examples of 

measures that may not be counted toward meeting a CO2 emission 
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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,812 direct air capture, 

and crediting of CO2 emission reductions that occur in the 

transportation sector as a result of vehicle electrification. 

2. Requirements for rate-based emission trading approaches 

 As with all approaches under the emission standards plan 

type, emission standards in a state plan that include a ratebased emission trading program must be quantifiable, verifiable, 

enforceable, non-duplicative and permanent.813 A state plan using 

a rate-based emission trading approach must include rate-based 

emission standards for affected EGUs along with related 

implementation and compliance requirements and mechanisms.814

These related requirements include those applicable to rate-

 

812 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.

813 These requirements are described in detail in section 

VIII.D.2.

814 As described below, these requirements would likely be 

provided in a state plan in the form of state regulations, but 

could potentially be provided in another form. 
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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.815

These requirements specific to rate-based emission trading 

programs are design elements the EPA has determined are 

necessary to assure the integrity of a rate-based approach that 

includes an emission trading program, and therefore assures a 

state plan using such an approach appropriately provides for the 

implementation of rate-based emission standards in accordance 

with CAA section 111(d).816 

 

815 See section VIII.G.1 for a discussion of the accounting 

method used to adjust a CO2 emission rate. 816 By “integrity of a rate-based emission trading program”, the 

EPA is referring to elements in the design and administration of 

a program necessary to assure that emission standards 

implemented using a rate-based emission trading approach are 
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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. For 

each design element, the EPA 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 

rest of the plan demonstrates to the EPA’s satisfaction that all 

other requirements, including that the rate-based emission 

standards meet the requirements addressed in section VIII.D.2 

and are appropriately demonstrated to achieve the CO2 emission 

performance rates or state CO2 goal. States may submit a ratebased emission trading program with alternative components other 

than those described, so long as the program includes each of 

 

quantifiable, verifiable, enforceable, non-duplicative, and 

permanent. 
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the required design elements and the state satisfactorily 

demonstrates in the state plan submittal that such alternative 

means of addressing the design elements are as stringent in all 

respects as the presumptively approvable approach as described, 

and therefore provide for the implementation of the state plan’s 

rate-based emission standards. 

The EPA also notes it is proposing model rules for both 

mass-based and rate-based emission trading programs.817 State 

plans that include the finalized model rule for a rate-based 

emission trading program will be presumptively approvable as 

meeting the requirements of CAA section 111(d) and these 

emission guidelines. 

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.818 

 

817 [Insert reference to FP/state plan model rule co-proposal.] 818 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 state-
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 ERCs may be used by an affected EGU to adjust its reported 

CO2 emission rate when demonstrating compliance with a rate-based 

emission limit. This adjustment is made by adding MWh to the 

denominator of an affected EGU’s reported CO2 emission rate, in 

the amount of submitted ERCs, resulting in a lower adjusted 

rate. To demonstrate compliance with a rate-based emission 

standard, an affected EGU would report its CO2 lb/MWh emission 

rate to the state regulatory body, and would also surrender to 

the state any ERCs it wishes to use to adjust its reported 

emission rate. The state regulator would then cancel the 

submitted ERCs. The affected EGU would add the MWh the ERCs 

represent to the denominator of its reported CO2 lb/MWh emission 

rate to demonstrate compliance with its emission standard. The 

state regulator could facilitate its evaluation of the affected 

EGU’s compliance (as well as evaluation by the affected EGU, the 

EPA, and others) by providing functionality in its tracking 

system to run such compliance calculations. If the affected 

EGU’s adjusted CO2 emission rate is equal to or lower than its 

 

administered 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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applicable emission rate standard, the affected EGU would be in 

compliance. 

a. Issuance of ERCs to affected EGUs. ERCs may be issued to 

affected EGUs that emit below a specified CO2 emission rate, as 

discussed below. For issuance of ERCs to affected EGUs, the 

state plan must specify the accounting method and administrative 

process for ERC issuance. This includes the calculation method 

for determining the number of ERCs to be issued to an affected 

EGU, based on reported CO2 emissions and MWh energy output, in 

comparison to a reference CO2 emission rate. The reference rate 

is a specified CO2 lb/MWh emission rate that an affected EGU’s 

reported CO2 emission rate is compared to, when determining the 

amount of ERCs that may be issued to an affected EGU.Following 

determination of the number of ERCs an affected EGU is eligible 

to receive, based on an affected EGU’s reported CO2 emission rate 

compared to a specified reference rate, the state regulatory 

body would issue those ERCs into a tracking system account held 

by the owner or operator of the affected 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 
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(e.g., if a plan is designed to meet a state rate-based CO2 goal) 

or separate rate-based emission standards that apply to 

subcategories of affected EGUs, namely fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. In both cases, ERCs are issued in MWh, 

based on the difference between an affected EGU’s reported CO2

emission rate (in CO2 lb/MWh) and a specified CO2 lb/MWh emission 

rate that the reported rate is compared to (referred to as a 

“reference rate”). The reference rate may be an affected EGU’s 

assigned CO2 emission limit rate or another CO2 emission rate, as 

described below. Where an affected EGU’s reported CO2 emission 

rate is lower than the specified reference CO2 emission rate, 

ERCs may be issued. 

Where a state plan includes emission standards in the form 

of a single rate-based emission standard that applies to all 

affected EGUs, the reference rate is the CO2 emission rate limit 

for affected EGUs. In this instance, ERCs may be issued based on 

an affected EGU’s reported CO2 emission rate as a proportion of 

the emission limit rate. For example, if the emission rate limit 

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 
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MWh increments. The calculation method is as follows: 

ERCs819 = reported MWh by affected EGU820 x ((CO2 emission 

rate limit for affected EGUs821 – affected EGU reported CO2

emission rate822)/ CO2 emission rate limit for affected EGUs) 

For the example above, the calculation is as follows: 

ERCs = MWh reported x (2,000 – 1,000)/2,000 = MWh reported 

x 0.5 

If the affected EGU in this example generated 1,000,000 MWh, 

500,000 ERCs would be issued. 

Where a state plan includes separate emission standards for 

subcategories of affected EGUs, specifically affected fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, the reference rate differs for 

affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. If the state plan 

applies emission standards for its affected EGUs that are equal 

to the subcategorized CO2 emission performance rates there is a 

unique opportunity for the adjustment of an affected EGU’s 

 

819 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

820 This term represents the reported MWh by the affected EGU on 

an annual basis. 

821 This term represents the “reference rate.” 822 This term represents the annual reported CO2 emission rate of 

the affected EGU.
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emission rate using ERCs that are generated as a result of 

building block 2 incremental NGCC operation. The EPA is 

requiring state plans to account for incremental NGCC generation 

in ERC generation if a state plan applies the sub-categorized CO2

emission performance rates to its affected EGUs as emission 

standards. Additionally, the EPA is requiring that NGCCs are not 

able to use ERCs generated by it or any other NGCC’s building 

block 2 incremental generation. These concepts are describe in 

the following examples and calculations. 

For affected steam generating units, the reference CO2

emission rate is the assigned CO2 emission rate limit for steam 

generating units, and the following accounting method for 

generating ERCs applies: 

ERCs823 = reported MWh x ((steam generating unit CO2 emission 

rate limit824 – steam generating unit reported CO2 emission rate)/ 

steam generating unit CO2 emission rate limit). 

For affected stationary combustion turbines, the accounting 

method for generating ERCs differs for “non-incremental” 

generation and “incremental” generation from the affected 

stationary combustion turbine. Incremental generation by an 

 

823 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued. 

824 The “reference rate.” 
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affected EGU is defined as annual energy generation, in MWh, 

that is greater than reported MWh generation by the EGU in 2012 

used in setting the CO2 emission performance rates in the 

emission guidelines. 

For an affected NGCC stationary combustion turbine, the 

following equations are an accounting method for generating ERCs 

based on operation expected in a sub-categorized rate-based 

emission trading program. The following equation applies for the 

non-incremental generation: 

ERCs = NGCC reported MWh x ((NGCC CO2 emission standard825 – 

NGCC reported CO2 emission rate)/ NGCC CO2 emission standard) 

According to this equation, ERC issuance is assessed based 

on the difference between the CO2 emission rate limit for the 

NGCC unit826 and the reported CO2 emission rate of the affected 

NGCC unit. In other words, affected NGCC stationary combustion 

turbines earn ERCs for non-incremental generation when they 

perform at an emission rate better than the reference rate for 

stationary combustion turbines, similarly to how affected steam 

units can earn ERCs. 

 To account for incremental generation for a NGCC 

 

825 The “reference rate.” 826 This is the CO2 emission performance level for affected 

stationary combustion turbines in the emission guidelines.
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stationary combustion turbine to generate ERCs, a state can use 

the incremental operation of an affected NGCC unit quantified 

for Building Block 2 to allow a NGCC unit to generate ERCs based 

on its expected incremental generation. In the following 

example, the EPA has taken the average NGCC stationary 

combustion turbine operation in the Eastern Interconnect and 

divided it by the 75 percent expected generation of Building 

Block 2 to calculate a Building Block 2 ERC generation rate of 

.09 ERCs/MWh. This factor can be applied to every MWh of 

generation by an affected NGCC unit to account for the effects 

of incremental operation of affected NGCC units across the 

system. The ERCs that are then generated can be used by any 

affected EGU that is subject to the sub-categorized steam 

generating unit CO2 emission performance rate. Using this 

methodology the quantity of ERCs generated can be calculated by 

the following equation for incremental building block 2 

generation: 

Building Block 2 ERCs = (NGCC reported MWh) x (building 

block 2 ERC generation rate .09 ERCs/MWh) 

Overall, this calculation method allows for issuance of 

ERCs based on the ability of incremental generation from 

affected stationary combustion turbines to substitute for 

Commented [A35]: Shouldn’t the amount of NGCC assumed 

match the level deployed in the BSER, which is less than 75%? 
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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 NGCC unit generates 1 

million MWh of electric output for the first year of the final 

plan performance period. During this year, it emits 850 million 

lbs of CO2, giving it an emission rate of 850 lb CO2/MWh. The 

affected NGCC is subject to a final period emission rate 

standard of 780 lbs CO2/MWh. Since the NGCC is subject to its 

NGCC emission rate standard of 780 lbs/MWh, and it is operating 

at a rate above that limit, it will owe ERCs for all generation, 

in order to meet its emision standard. The number of ERCs owed 

are calculated by solving for the number of ERC MWh the NGCC 

will need to adjust its reported CO2 emission rate down to its 

emission rate limit. This is shown in the following equation: 

ERCs = 1,000,000 MWh x ((780 lbs/MWh – 850 lbs/MWh)/ 780 

lbs/MWh) 

When that equation is solved for the number of ERC MWh needed, 

the affected NGCC unit would need to submit 89,744 ERCs to 

adjust its reported CO2 emission rate to its emission rate 
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standard. 

Additionally, according to the previous equation, the 

building block 2 ERCs generated can be calculated by the 

following equation: 

Building Block 2 ERCs = (1,000,000 MWh) x (.09 ERCs/MWh) 

The calculation results in 90 thousand building block 2 

ERCs being generated. Because an affected NGCC unit cannot use 

the building block 2 ERCs it generates to meet its compliance 

obligations, this affected NGCC will both generate ERCs (90,000 

ERCs for its incremental building block 2 generation) and owe 

ERCs (it will need to submit 89,744 ERCs to meet its emission 

standard). This affected NGCC unit may sell (or otherwise 

transfer) or bank its building block 2 ERCs. 

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 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, which is based on use of 
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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.827 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 project828 to the 

administering state regulator (or its agent829). The state 

regulator reviews the application to determine whether, in this 

example, an EE/RE program or project meets eligibility 

 

827 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.

828 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. 

829 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.830 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.831 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 

 

830 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. 

831 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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by an accredited independent verifier prior to submittal. This 

requirement builds on the approach used for assessing GHG offset 

projects, both in international emission trading programs and 

the GHG emission budget trading programs implemented by 

California and the RGGI participating states.832 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. 

Inclusion of an independent verification component is also 

 

832 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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consistent with similar approaches required by state PUCs for 

the review of demand-side EE program results and GHG offset 

provisions included in state GHG emission budget trading 

programs. 

 Rate-based emission trading programs used in a state plan 

must include requirements for independent verifiers that specify 

necessary qualifications and codes of conduct when providing 

verification services. State requirements must include 

accreditation requirements for independent verifiers that 

specify that only accredited verifiers may provide verification 

services and detail the requirements for accreditation and 

maintenance of accreditation status.833 

 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 

 

833 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. 

Commented [A36]: Is it possible to require that states pay 

verifiers, using project fees, so that independence is maintained? 
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they have a financial, management, or other interest.834 Such 

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 

 

834 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 

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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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 

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.835 

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 

 

835 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. 
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program or project, and to only one state program.836 These 

provisions will ensure that actions that are eligible for the 

issuance of ERCs are “non-duplicative.”837 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 

of the RE/EE program or project (as described in this example) 

that was approved in step one, the RE/EE provider periodically 

submits a 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.838 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 

 

836 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. 

837 Emission standards must be “non-duplicative” as described in 

section VIII.D.2. 

838 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. These reporting periods 

should be annual, but a state could consider short or longer 

periods, depending on the type of ERC resource. 
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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 

is submitted only once for each RE/EE action, and to only one 

state program.839 The tracking system must provide transparent 

electronic public access to submitted M&V reports and regulatory 

approvals related to such reports.840 Such reports are the basis 

for issuance of ERCs. 

c. Tracking system requirements. State requirements must include 

 

839 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. 

840 This must include electronic Internet access to such 

information in the tracking system. 
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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,841 and an accompanying tracking system 

infrastructure design based on business rules specified in the 

emission trading program regulations. Each issued ERC must have 

a unique identifier (e.g., serial number) and the tracking 

system must provide for traceability of issued ERCs back to the 

program or project for which they were issued. 

The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading systems. This 

could include regional systems and/or a national system. The EPA 

 

841 “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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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 

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 

Commented [A37]: Is this consistent with what the FP says? 
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provisions making clear that an affected EGU may only use 

properly issued, valid ERCs to demonstrate compliance with its 

emission standard. An affected EGU that submits for compliance 

with its emission standard an ERC that does not actually 

represent an eligible MWh of zero-emission electricity 

generation or savings (for the purposes of meeting the emission 

guidelines) must submit one properly issued, valid replacement 

ERC for each improperly issued ERC to the state regulatory body 

within a specified period of time, in accordance with the 

emission guidelines. This period of time for replacement with a 

valid ERC is specified as a period subsequent to the date that 

an ERC submitted for demonstrating compliance with an emission 

standard is found to have been improperly issued. An affected 

EGU that fails to submit the necessary number of replacement 

ERCs within this specified period is subject to CAA liability 

for failure to meet its emission standard for each day of the 

relevant compliance period. This is true regardless of the good 

faith of the EGU in purchasing or obtaining the ERC. However, 

the EPA notes that the integrity elements included in the design 

of a rate-based emission trading program, as required in the 

emission guidelines, will greatly reduce the potential for 

improperly issued ERCs and the accompanying potential CAA 

Commented [A38]: It would be helpful to understand why this 

change was made, as it seems to dilute the incentive significantly 
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liability for affected EGUs if such ERCs are submitted for 

demonstration of compliance with an emission standard. The 

ability for affected EGUs to replace such improperly issued 

ERCs, if submitted for compliance, further limits this potential 

CAA liability for affected EGUs. 

e. Banking of ERCs. ERCs issued in 2022 or a subsequent year may 

be carried forward (or “banked”) and used for demonstrating 

compliance in a future year.842 For example, an ERC issued for a 

MWh of RE generation that occurs in 2022 may be applied to 

adjust a CO2 emission rate in 2023 or future years without 

limitation. ERCs may be banked from the interim plan performance 

period to the final plan performance period. Banking provides a 

number of advantages while ensuring that the same outputweighted average CO2 emission rates of the interim and final 

state CO2 goals are achieved over the course of a state plan. 

Banking provisions have been used extensively in rate-based 

environmental programs and mass-based emission budget trading 

programs.843 This is because banking reduces the cost of 

 

842 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). 

843 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).
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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.844

f. Considerations for ERC issuance. The EPA notes that stateadministered and state-overseen EE programs, such as those 

administered by state-regulated electric distribution utilities, 

could play a key role in supplying energy savings to a ratebased emission trading system in the form of ERCs. These 

programs have been the primary means for delivering EE programs 

and energy savings at scale, and also allow for a state to 

conduct a portfolio planning process to guide EE program design 

 

844 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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and focus in a manner that best provides multiple benefits to 

electricity ratepayers in a state. Such portfolio planning 

processes typically treat EE as an energy resource comparable to 

electricity generation. 

 The EPA also notes that non–ERC certificates may be issued 

by states and other bodies for MWh of energy generation and 

energy savings that are used to meet other state regulatory 

requirements, such as state RPS and EERS, or by individuals to 

make environmental or other claims in voluntary markets. 

 The EPA defines an ERC in the emission guidelines as a 

tradable compliance instrument that represents a zero-emission 

MWh (for the purposes of meeting the emission guidelines) from a 

qualifying measure that may be used to adjust the reported CO2

emission rate of an affected EGU subject to a rate-based 

emission standard in an approved state plan under CAA section 

111(d). The sole purpose of an ERC is for use by an affected EGU 

in demonstrating compliance with a rate-based emission standard 

in such an approved state plan. 

 An ERC is issued separately from any other instruments that 

may be issued for a MWh of energy generation or energy savings 

from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as 
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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. 

g. Program review. The EPA is requiring that states periodically 

review the administration of their state rate-based emission 

trading program. This program review must be submitted as part 

of a required state report to the EPA on the implementation of 

its state plan, as described in sections VIII.D.a.(5), 

VIII.D.2.b.(4) (for emission standards plan types), and 

VIII.D.2.c.(5) (for state measures plan types). For a rate-based 

emission trading program administered under an emission 

standards plan type, the evaluation must cover the multi-year 

period addressed in the state’s report to the EPA on plan 

implementation. For a rate-based emission trading program 

administered under a state measures plan type, the evaluation 

must cover the annual period addressed in the state’s report to 

the EPA on plan implementation. 

 The program review must address all aspects of the 

administration of the program, including state evaluations and 

regulatory decisions regarding eligibility applications for ERC 

resources and M&V reports (and associated EM&V activities), and 
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state issuance of ERCs. The program review must assess whether 

the program is being administered properly in accordance with 

the approved plan, that reported annual MWh of generation and 

savings from qualified ERC resources are being properly 

quantified, verified, and reported in accordance with approved 

EM&V plans, and that appropriate records are being maintained. 

The program review must also address accreditation of verifiers 

by the state and the conduct of verifiers, including the quality 

of verifier reviews. Where significant problems are identified 

by the state’s program review, those problems shall be rectified 

by the state in a timely manner. 

 States must compile and maintain sufficient data to support 

the program review. Maintenance of such data will provide the 

EPA, if it chose, with the ability to audit a state’s 

administration of its rate-based emission trading program. 

3. EM&V requirements for RE, demand-side EE, and other measures 

used to adjust a CO2 rate 

This section identifies and discusses the EM&V requirements 

used to quantify MWh from demand-side EE, RE, and other measures 

used to generate ERCs or otherwise adjust an emission rate.845

 

845 EM&V is defined to mean the set of procedures, methods, and 

analytic approaches used to quantify the MWh from demand-side EE 
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These requirements apply in the context of both emission 

standard plans and state measures plans, as described below. 

Rate-based state plans that include these measures must require 

that all MWh saved and generated from eligible measures are 

quantified per the requirements below.846 

Additionally, with respect to these requirements, the EPA 

describes certain established industry best practices that would 

be presumptively approvable as an approach to include these 

requirements in state plans. States must submit these 

requirements as specified, or alternatively, states may submit 

the industry best-practices described as presumptively 

approvable. States may also submit other means of meeting the 

requirements so long as the state demonstrates to the EPA’s 

satisfaction in the state plan submittal that such alternative 

means of addressing requirements are as rigorous as the 

presumptively approvable approach described here. 

 

and RE and other measures, and thereby ensure that the resulting 

savings and generation are quantifiable and verifiable. 

846 For a rate based emission standards plan type, the 

requirement to quantify the MWh per the EM&V requirements 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 per 

the EM&V requirements, and such state only requirements must be 

adequately described in the supporting documentation submitted 

with the state plan. 

Deleted: stringent
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As discussed in VIII.G.4, quantified and verified MWh of RE 

generation, EE savings,847 and other eligible measures may be 

used to adjust a CO2 emission rate when demonstrating compliance 

with the emission guidelines. In states implementing emission 

standard type plans with rate-based trading, affected EGUs 

adjust their reported emission rate using ERCs, which represent 

MWh that are quantified and verified according to the EM&V 

requirements included in this section. Providers other than 

affected EGUs who seek to earn ERCs must develop EM&V plans 

outlining how they will quantify and verify the results of their 

efforts. These providers must then submit these EM&V plans as 

part of their application to the state regulatory body for 

project approval.848 

In states implementing state measures type plans, 

quantified and verified MWh of RE, EE, and other eligible 

measures may be used to adjust an emission rate where all other 

 

847 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. 

848 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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applicable requirements under this final rule have been met. Two 

general pathways are available to adjust emission rates. 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 

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 state goal. For an emission standards plan, the ERC 

issuance and EM&V requirements must be submitted as a component, 

subject to approval, of the federally enforceable state plan. 

If the state elects to incorporate RE, demand-side EE, and 

Commented [A39]: Reviewer recommends the following 

language in the appropriate place to reference ERC trading 

programs: 

“For RE or NGCC measures (in either a mass state or a rate state) to 

have some or all of its generation counted under a rate-based plan, it 

must be demonstrated that the generation was delivered to the grid to 

meet electricity load in that rate based state or another rate based 

state within the same rate trading system. For EE measures to have 

some or all of its generation savings counted under a rate-based plan, 

it must be demonstrated that measures reduced generation from 

affected sources in that rate based state or another rate based state 

within the same rate trading system. EPA will provide guidance 

outlining presumptively approvable demonstrations.” 
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other eligible 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 and reports how the requirements 

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 requirements for 

zero-emitting RE, demand-side EE, and other measures implemented 

through both types of state plan approaches, followed by a 

presentation of some additional considerations for states 

implementing these measures in the context of a state measures 

plan without rate-based trading. 

4. Overall approach and measure-specific requirements 

The proposed rule stated that the EPA would establish EM&V 

requirements and procedures to help states, sources, and RE and 

EE providers quantify and verify MWh savings and generation 

resulting from zero-emitting RE and demand-side EE efforts. The 

proposal and associated “State Plans Considerations” TSD849

 

849 See discussion beginning on p. 34 of the State Plan 

Considerations TSD for the Clean Power Plan Proposed Rule: 
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suggested that the EPA’s EM&V requirements would leverage the 

industry-standard practices, protocols, and tracking mechanisms 

currently utilized by the majority of states currently 

implementing RE and demand-side EE. The EPA further noted that 

many state regulatory bodies and other oversight 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, 

particularly with regard to the quantification and verification 

of energy savings resulting from utility-administered EE 

programs. The EPA also observed that the majority of RE 

generation is typically quantified and verified using readily 

available, reliable, and transparent methods such as the direct 

metering of MWh. 

As a result, the agency took comment on whether this 

infrastructure is appropriate to use as the basis for 

establishing minimum EM&V requirements for use in rate-based 

state plans that include RE, demand-side EE, and other measures. 

The majority of commenters addressing this question indicated 

that existing EM&V infrastructure is appropriate to assure 

 

http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations. 
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quality, credibility, and integrity. The EPA agrees with this 

assessment and is finalizing a set of EM&V requirements, 

described herein, that is intended to be consistent with and 

leverage prevailing industry practices. 

In addition, the EPA’s final requirements 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 requirements is to avoid excessive 

interference with EM&V practices that are already robust, 

transparent and working well. The EPA also seeks to ensure that 

the procedures required to quantify RE generation for purposes 

of demonstrating compliance with a state's CO2 emission rate goal 

are consistent with the procedures relied on by the EPA for 

purposes of quantifying the role that RE generation plays in 

determining the BSER, which in turn underlies each state's CO2 

emission rate goal. 

a. Submittals. Applicable submittals under a rate-based emission 

trading program must include eligibility applications (which 

include EM&V plans) and monitoring and verification reports. 
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These submittals are described in section VIII.K.2. At the 

initiation of a program or project, an ERC provider must develop 

and submit to the state an EM&V plan that documents how 

applicable requirements will be addressed as EM&V is performed 

over the program or project reporting period. After 

implementation has occurred, the ERC provider must submit 

periodic monitoring and verification (M&V) reports on an ex-post 

basis to document and describe how each of the requirements was 

applied. These reports must also specify the resulting MWh 

savings or generation values per RE, EE, and other program and 

project categories. 

For demand-side EE, all EM&V plans that are developed for 

purposes of adjusting an emission rate under this final rule are 

intended to leverage and closely resemble the plans 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 MWh 

tracking for RE that are broadly applied in the state and 

regions. The existing reports and documentation from existing 

tracking systems may serve as the substantive basis for a 

monitoring and verification report for RE. 

For all EE-related EM&V submittals under both state plan 
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types, the required metric is electricity savings, which is 

defined as a reduction in electricity consumption due to a 

demand-side EE program, project, or measure used to adjust an 

emission rate. EE savings must be quantified and reported in 

units of MWh. Additional procedures and requirements for EM&V 

submittals in the context of an emission standard plan are 

outlined above in section VIII.G.3. For state measures plans, 

this information is provided below in section VIII.G.5. 

b. EM&V requirements that apply to all demand-side EE used to 

adjust an emission rate. The following EM&V requirements apply 

to all demand-side EE used to adjust an emission rate. 

(1) Baseline definitions. Based on public input and assessments 

of best practices, the EPA has determined that a “common 

practice baseline” (CPB) must be used to determine MWh savings. 

A CPB is the system or measure a typical consumer or building 

owner would have continued using or installed at the time of the 

project implementation, in the absence of the demand-side EE 

program, project, or measure. The applicable CPB depends on a 

number of factors, such as characteristics of the EE measure, 

the delivery mechanism to implement the EE measure, local 

consumer and market characteristics, and the applicable building 

energy codes and product standards (C&S), including the C&S 

Formatted: Highlight
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compliance rate. EE providers can refer to the EPA’s EM&V 

guidance for descriptions of appropriate CPBs to apply in 

specific contexts, with consideration of these factors. EE 

providers must document the selected CPB in their EM&V plans, 

along with clear documentation and discussion of the rationale, 

applicability, and relevant data sources, protocols, and other 

supporting information.850 Monitoring and verification reports 

must refer to the EM&V plan and confirm the CPB that was 

applied. 

(2) EM&V methods used to quantify the results of EE projects and 

programs. This section establishes requirements for the general 

types of EM&V methods that EE providers may use to quantify the 

MWh savings from demand-side EE programs, projects, and 

measures. Consistent with EM&V best practices at the state level 

– in which PUCs typically allow utilities and other EE 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 providing flexibility for EE providers to select 

 

850 For one source of applicable baselines, see Table 7.1. State 

and Local Energy Efficiency Action Network. 2012. Energy 

Efficiency Program Impact Evaluation Guide. Prepared by Steven 

R. Schiller, Schiller Consulting, Inc., 

www.seeaction.energy.gov. Or current version.
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from three broad categories of EM&V methods to determine 

savings. 

These categories include project-based measurement and 

verification (M&V), deemed savings, and comparison group 

approaches such as randomized control trials (RCT). Regardless 

of the approach selected, a key requirement, supported by 

commenters and consistent with industry best 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 must 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. EM&V using the above methods must occur at a minimum of 

four year intervals for building energy codes and product 

standards; every one, two or three years for publicly or ratepayer funded EE programs, depending on the program type, 

magnitude of savings, and experience with the program; and 

annually for large individual commercial and industrial 

projects. For all demand-side EE used to adjust an emissions 

rate, the selected method, associated assumptions, and data 
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sources must be identified and described in EM&V plans. 

For comparison group approaches, the key EM&V requirement 

is to follow industry best 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, which determine 

savings on the basis of energy consumption differences between a 

treatment group and a comparison group, and therefore increase 

the reliability of results. 

As noted above, an alternative to the comparison group 

methods is the use of deemed savings, which establishes predetermined annual electricity savings values for specific EE 

measures. The applicable requirements for using deemed savings 

are that all savings values must be documented in a publicly 

available database (frequently referred to as a technical 

reference manual, or TRM) and be reviewed and updated at least 

every 3 years to keep current with market trends and technology 

innovation. The TRM must additionally indicate, for each value, 

the conditions for which the value can be applied (i.e., 

climate, building type, and implementation mechanism). 

For M&V methods, industry best-practice protocols must be 

followed. These include the IPMVP, protocols published by the 

Formatted: Highlight

Formatted: Highlight
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Federal Energy Management Program (FEMP), the American Society 

of Heating, Refrigeration and Air-Conditioning Engineers 

(ASHRAE), and the U.S. DOE’s UMP. EE providers can also consult 

the EPA’s EM&V guidance to assess the applicability of such 

protocols and guidelines to the EE programs and projects 

generating savings, and must document how these will be applied 

in EM&V plans (along with clear documentation and discussion of 

the rationale, applicability, and relevant data sources, and 

other supporting information). Monitoring and verification 

reports must refer to the EM&V plan and confirm that the 

relevant protocol was applied. 

(3) Quantifying savings. Regardless of the approach used to 

quantify and verify MWh savings, EM&V plans must describe how 

they will address the following: 

 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 must be calculated 

using industry best-practices such as real-time 

conditions or normalized conditions that are reasonably 

expected to occur throughout the lifetime of the EE 

project or measure. 
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 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 are evaluated 

site-by-site). Verification is required within the first 

year of program implementation. All verification 

activities must be performed using industry best-practice 

techniques (e.g., phone or mail surveys, document review, 

site inspections, spot or short-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. 

 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 

optimization851) may adjust reported savings by using a 

T&D. If such an adder is used, it must be based on the 

lesser of 6 percent852 of the site-level savings or the 

 

851 More information about these technologies is in section 

VIII.F.1 above. 

852 6 percent is the national average losses from 1990-2012 (See: 

http://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3). 
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calculated statewide annual average T&D loss rate 

[estimated losses in MWh/(total electric supply – direct 

electricity use)]853 expressed as a percentage and based 

on values in the most recent year and published US EIA 

State Electricity Profile. For Volt/var optimization and 

conservation voltage reduction (CVR) – that reduce both 

line losses and facility-level MWh consumption – the 

quantification procedures that will be used to identify 

facility portion of overall savings must be identified in 

an EM&V plan consistent with the requirements for 

quantification provided here. 

 How the duration of EE program or project electricity 

savings will be determined. This must be determined using 

industry best practices such as annual verification 

assessments, industry-standard persistence studies, 

deemed estimates of effective useful life (EUL), or a 

combination of all three. If project or program 

 

853 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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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 rigor854 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 

and cited. 

 

854 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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 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. In public comments, the EPA heard 

overwhelmingly that such protocols 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 is therefore requiring the application of industry bestpractices for demand-side EE. EM&V plans must include a clear 

description and documentation of how the relevant protocols will 

be applied, as well as after-the-fact documentation in EM&V 

reports of how they were actually applied. EE providers can 

refer to the EPA’s EM&V guidance document for information about 

protocols that are currently available. 

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 
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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 requirements for eligibility described in section 

VIII.G.1., and that supporting EM&V is rigorous, complete and 

fulfills the requirements 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 

standards 

The EPA recognizes that the programs and policies listed 

above will evolve and change over the rule period, as new 
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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 they meet the 

requirements of the emission guidelines. 

d. Demand-side EE program- and project-specific EM&V provisions. 

In addition to the generally-applicable EM&V requirements 

specified above, EM&V plans and monitoring and verification 

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 

any applicable industry-standard protocols that are relevant to 

such programs, projects, and measures will be and have been 

applied. EE providers can refer to the EPA’s EE EM&V guidance 

for more information on such protocols. The EPA anticipates that 

other protocols and EM&V resources may be developed during the 

course of rule implementation, 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 

Commented [A40]: Would it be possible to retain the potential 

to update and revise EM&V criteria over time, as best practices 

evolve / issues are identified? EPA could require states to update 

and revise that portion of their state plans in a simple modification 

process? 
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relative to the applicable CO2 emission rate for affected EGUs in 

the state. 

 The CHP unit’s electrical output would be prorated based on 

the CO2 emission rate of the electrical output associated with 

the CHP unit.855 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 

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

 

855 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. 

Commented [A41]: Could you explain how this is consistent 

with the requirement that only displacement of regulated source 

emissions (via reduced demand) are credited? 
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output.856 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 facilities857 with electric generating 

capacity greater than 100 MW would follow the same monitoring 

and reporting protocols for CO2 emissions and energy output as 

are required for affected EGU CHP units. These requirements are 

discussed in section VIII.F. For non-affected CHP facilities 

with electric generating capacity less than 100 MW, which use 

only natural gas and/or distillate fuel oil, the low mass 

emission unit CO2 emission monitoring and reporting methodology 

outlined in 40 CFR 75 is acceptable. 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 controlarea operators; or (2) for customer-sited CHP that is 

interconnected behind the customer meter, a revenue quality 

 

856 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. 

857 A CHP facility may consist of one or more electric 

generators. 
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meter at the AC output of an inverter, where applicable, that is 

adjusted to reflect the energy delivered into either the 

transmission or distribution grid at the generator bus bar. 

For small systems, defined as individual CHP units with 

nameplate capacities below 10 kW where metered data are 

unavailable, generation output may be determined using either 

self-reporting of generation values858 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 

 

858 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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confirm that rigorous quality control and fraud prevention 

measures are in place. Small systems are defined as individual 

CHP units with nameplate capacities below 10 kW where metered 

data are unavailable. For CHP systems that directly serve onsite end-use electricity loads, avoided T&D system losses can be 

assessed as is commonly practiced with demand-side EE. Such 

calculations must apply the requirements described in section 

VIII.G.4.(b)(3) above. 

f. EM&V requirements that apply to all RE. This section 

describes the EM&V requirements associated with quantifying 

electricity generation from eligible RE, and for documenting 

these requirements in EM&V plans and reports. Consistent with 

prevailing views expressed in public comments, the EPA’s 

requirements 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 certificates (RECs). These registries typically 

include well-established procedures for registry operations, 

safeguards, and documentation, all of which support compliance 

demonstration with state RPS policies. Therefore, each RE unit 

must be uniquely identified and recorded in a registry to avoid 

double counting. 
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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 

customer meter, measurement 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. 

Further, a RE generating facility of 10 kW capacity or less may 

estimate the facility’s output if the state where it is located 

explicitly allows estimates to be used and provides rules for 

when it will be allowed. 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. 

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 
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operator to the REC registry at least monthly. 

For RE units that do not go through a control area 

settlements process, metered data may be read and transmitted to 

the ERC registry by an independent third party, or may be selfreported. Third-party and self-reported generation data should 

be reported on a monthly basis, but accommodation may be made 

for small systems that do not generate enough electricity to 

warrant monthly reporting, but at a minimum annually. Such data 

must be verified for reasonableness by the state or the REC 

registry. 

For reporting purposes, RE generation may be aggregated 

from multiple generators into a single MWh value for the group, 

provided the following requirements, or alternative requirements 

approved by the EPA in connection with a specific state plan, 

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 units aggregated are located in 

the same state, and 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 
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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 

requirements specified for demand-side EE, as described in 

section VIII.G.4.(b)(3) above. 

(1) EM&V requirements that apply to incremental hydroelectric 

power. Generation (in MWh) from incremental hydroelectric power 

generating capacity is determined as follows. The incremental 

generating capacity (in MW) is divided by the total uprated 

generating capacity (in MW) and then multiplied by generation 

output (in MWh) from the uprated generator. For example, if a 

hydroelectric power plant expands generating nameplate capacity 

from 100 MW to 125 MW and generation output increased to 1,000 

MWh, then 200 MWh ((25 MW/125 MW) * 1,000 MWh) is eligible for 

use in adjusting a CO2 emission rate, regardless of the overall 

level of generation for the period.859 Applicable generation (in 

MWh) from incremental nuclear power is determined in the same 

manner as that described for incremental hydroelectric power 

 

859 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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above. 

(2) EM&V requirements that apply to biomass RE facilities. An 

EM&V plan that addresses biomass RE must follow the requirements 

for monitoring and reporting biogenic CO2 emissions from the 

facility that were approved by the EPA in connection with the 

specific state plan. 

(3) EM&V requirements that apply to waste-to-energy facilities.

An EM&V plan that addresses the biogenic CO2 emissions from a 

waste-to-energy facility must follow the requirements for 

monitoring and reporting biogenic CO2 emissions from the facility 

that were approved by the EPA in connection with the specific 

state plan. If a state include the requirements for biogenic CO2

emissions in 40 CFR 98 (§§ 98.3(c), 98.36(b)-(d), 98.43(b), and 

98.46) in its plan submission, those requirements are 

presumptively approvable. The EPA may approve other requirements 

of similar rigor, at its discretion. 

As discussed above, in section [...], only the portion of 

electric generation at a waste-to-energy facility that is due to 

the biogenic content of the MSW may be used to generate ERCs or 

counted by a state towards its achievement of its obligations 

pursuant to this regulation. 

Measuring the proportion of biogenic to fossil CO2 emissions 
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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 facility that 

may be used to adjust an affected EGU CO2 emission rate. 

g. Considerations for EM&V of T&D efficiency measures. 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 
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was cited as a rationale for their inclusion as an eligible 

measure that can be used to adjust a CO2 emission rate. 

h. 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 requirements (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 
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implement, as well as a discussion of how it intends to quantify 

the results of those measures consistent with the EMV 

requirements described herein. A key component of this 

discussion is the mechanisms and approaches the state intends to 

apply to ensure that MWh savings and generation are 

independently and credibly quantified and verified. 

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.860

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 program- and 

project-level EM&V reports used to compile total MWh savings and 

generation. EM&V reports must document how EM&V requirements 

were applied to quantify results. 

Going forward, the EPA recognizes that EM&V is routinely 

evolving to reflect changes in markets, technologies and data 

 

860 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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availability, and expects to update its EM&V guidance over time. 

Therefore the agency expects that new quantification approaches 

can be applied in the context of achieving the emissions goals, 

and that the EPA will approve the use of such approaches 

provided that they are functionally equivalent to the provisions 

for EM&V outlined in this section and in section VIII.G.3. Such 

approaches would likely be consistent with the delivery of total 

planned demand-side EE, while acknowledging historical 

experience that some individual EE programs over-perform and 

some under-perform over time. The agency may issue additional 

guidance outlining how verification of MWh savings could be 

performed at a higher level of aggregation.

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.

i. Skill certification standards. Using a skilled workforce to 

implement demand-side EE and RE projects, and to evaluate, 

measure and verify the savings associated with EE projects or 

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the additional generation from performance improvements at 

existing RE projects are both important. Several commenters 

pointed out that skill certification standards can help to 

assure quality and credibility of demand-side EE and RE 

projects. The EPA also recognizes that a skilled workforce 

performing the EM&V is important to substantiate the 

authenticity of emissions reductions.

 The EPA agrees that in conjunction with other EM&V measures 

discussed in this section, recommending that workers installing 

demand side EE and RE projects as well as workers who perform 

the EM&V of demand side EE and RE performance be certified by a 

third party entity that: 

1) Develops a training or competency based program 

aligned with a job task analysis and/or certification scheme; 

2) Engages with subject matter experts in the 

development of the job task analysis and/or certification 

schemes that represent appropriate qualifications, categories of 

the jobs, and levels of experience; 

3) Has clearly documented the process used to 

develop the job task analysis and/or certification schemes, 

covering such elements as the job description, knowledge, 

skills, and abilities; 

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4) Has pursued third-party accreditation aligned 

with consensus-based standards, for example ISO/IEC 17024 or 

IREC 14732. 

Examples of such entities include: parties aligned with the 

accrediting body recognized by Department of Energy’s (DOE) 

Better Building Workforce Guidelines and validated by a third 

party accrediting body recognized by DOE; or parties aligned 

with an apprenticeship program that is registered with the 

federal Department of Labor (DOL), Office of Apprenticeship; or 

with a state apprenticeship program approved by the DOL, or by 

another skill certification validated by a third party 

accrediting body can help to substantiate the authenticity of 

emission reductions due to demand-side EE and RE. 

4. Multi-state coordination: rate-based emission trading 

programs 

 Individual rate-based state plans may provide for the 

interstate transfer of ERCs, which would enable an ERC issued by 

one state to be used for compliance by an affected EGU with a 

rate-based emission standard in another state. Such plans would 

include regulatory provisions in each state’s emission standard 

requirements that indicate that ERCs issued in other partner 

states may be used by affected EGUs for compliance. Such plans 
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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.861

 The approaches described in this subsection are only 

allowed for states that impose rate-based emission limits for 

affected EGUs that are equal to the CO2 emission performance 

levels provided for [steam and gas] in the emission guidelines. 

This approach is necessary to ensure that each state that is 

allowing for the interstate transfer of ERCs is implementing 

rate-based emission standards for affected EGUs at the same lb 

CO2/MWh level.862 This assures that all the participating states 

are issuing ERCs to affected fossil steam and NGCC units that 

 

861 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. 

862 As noted above in section VIII.C.5.b, states also have the 

option of implementing a multi-state plan with a single ratebased emission standard that applies to all affected EGUs in the 

participating states. This approach would also allow for 

interstate transfers of ERCs. Under this approach, a rate-based 

multi-state plan would include emission standards for affected 

EGUs based on a weighted average rate-based emission goal, 

derived by calculating a weighted average CO2 emission rate based 

on the individual rate-based goals for each of the participating 

states and 2012 generation from affected EGUs.

Commented [A42]: To distinguish from the blended state rates 

also provided in the EGs 
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emit below their assigned emission standards on the same basis. 

 This approach avoids providing different incentives, in the 

form of issued ERCs, to affected steam generating units and NGCC 

units in different states that have comparable CO2 emission 

rates. Providing different incentives to similar affected EGUs 

across states could create distortionary effects that lead to 

shifts in generation among states based on the different CO2

emission rate standards applied by states to similar types of 

affected EGUs. Providing for the interstate trade of ERCs in 

this instance would exacerbate these distortionary effects by 

providing arbitrage opportunities. 

 When demonstrating that a state’s CO2 emission goal is 

achieved as a result of plan implementation, a state with 

linkages to other states would be required to demonstrate that 

any ERCs issued by another state that are used by affected EGUs 

in the state for compliance with its rate-based CO2 emission 

standards were issued by states with an EPA-approved state 

plan.863

 States could implement these linkages among state plans 

 

863 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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with rate-based emission trading systems through three different 

applied implementation approaches: (1) plans that are “readyfor-interstate-trading;” (2) plans that include specified 

bilateral or multilateral linkages; and (3) plans that provide 

for joint ERC issuance among states with materially consistent 

regulations. These approaches are summarized below: 

 Ready-for-interstate-trading plans: A state plan recognizes 

ERCs issued by any state with an EPA-approved plan that 

also uses a specified EPA-approved864 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.865

 

864 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. 

865 The EPA notes that it is proposing a model rule for a ratebased emission trading program that could be used by states 

interested in implementing a ready-for-interstate-trading plan 

approach. [Insert reference to the FP/state model rule 

proposal.] A state plan that included the adopted rate-based 

model rule will be presumptively approvable as meeting the 

requirements of CAA section 111(d) and the emission guidelines. 

Commented [A43]: Is this a blended rate framework or a 2 rate 

framework? 
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 Specified bilateral linkage: States recognize ERCs issued 

by named partner states. Partner states must demonstrate 

that they use a shared tracking system, interoperable 

tracking systems, or an EPA-administered tracking system. 

Plans are approved individually, including review of the 

shared tracking system or interoperable tracking systems. 

 Joint ERC issuance: States implement materially consistent 

rate-based emission trading program regulations and share a 

tracking system. States coordinate their review of 

submissions for ERC issuance866 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 

 

If a state plan also met the requirements described in this 

subsection for ready-for-interstate-trading plans, it could be 

approved as ready-for-interstate trading. 

866 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. 

Commented [A44]: Does this require all to be 2 rate or all to be 

blended rate across the group? 
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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.867 

L. Treatment of Interstate Effects and Addressing Potential 

Leakage 

 This section discusses how differing characteristics across 

states and sources could create risks of increased emissions 

under this rule through double counting of emission reduction 

measures or through foregone emission reductions due to movement 

of generation from source to source. The section also discusses 

how the final rule addresses these concerns: first, through the 

characteristics of goal-setting and the framework of state 

plans, and second, through specific requirements intended to 

 

867 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 

implementation of rate-based plans across states while retaining 

individual rate-based state goals. 
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minimize the risk of double counting and increased emissions. 

The section is structured as follows. First, this section 

discusses the dynamics that cause these risks to potentially 

arise. Second, it provides a discussion of how the risks of 

double counting and foregone reductions are minimized through 

the following provisions: multi-state plan options that limit 

distortionary effects, the structure of mass-based plan and 

rate-based plan accounting for emission reductions measures, and 

specified restrictions on the counting in a rate-based plan of 

emission reduction measures located in a mass-based state. 

Third, the section discusses the risk of leakage, how it is 

minimized in a rate-based context and across existing sources, 

and specifies a demonstration required in mass-based plans to 

address leakage to new sources. Finally, the section discusses 

how the rate-based accounting framework minimizes incentives to 

develop emission reduction measures in particular states due to 

differences in rates. 

In the June 2014 proposal, the EPA acknowledged that 

emission reduction measures implemented under a state plan will 

likely have impacts across many affected sources both within and 

across state boundaries due to the dynamic and interstate nature 

of the electric grid, as is discussed above in section VIII.K.1. 
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These interactions may be driven in part due to differences in 

power sector dynamics across states, including the types of 

affected EGUs in a state, the availability of eligible nonemitting resources, and the costs of different compliance 

options and existing policies in states. These state-level 

characteristics play out across dynamic regional grids that 

provide electricity across states. EGUs are dispatched both 

within and across state borders and are constantly adjusting 

behavior in response to available generation and electricity 

demand on the regional grid. Whenever CO2 emission reduction 

measures, such as RE or demand-side EE, are implemented, the 

measure can affect EGU generation and CO2 emissions across the 

regional grid. These impacts can change across multiple affected 

EGUs on a minute-to-minute, hour-to-hour, and day-to-day basis 

as electricity demand changes and different generating resources 

are dispatched. These impacts will also change in the long-term, 

as the generating fleet and load behavior change over a period 

of years. Interactions among EGUs across states may be further 

driven by the plan types (i.e., rate-based or mass-based) and 

the individual characteristics of the plans that states choose 

to adopt. 

In the context of this complex environment of federal and 
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state policies and interstate grids, commenters expressed 

concern about the risk of double-counting of measure impacts, 

particularly across state plans. Commenters stated that there 

is potential for distortionary incentives that could undermine 

overall CO2 emission reductions (often termed emissions 

“leakage”). Commenters requested that the EPA ensure that states 

avoid double-counting and minimize leakage effects when 

demonstrating achievement of state goals and minimize leakage 

effects. 

The EPA acknowledges that some amount of shifts in 

generation between sources within and across state borders will 

inevitably be present and unavoidable in the context of this 

rule and may affect how affected EGUs achieve the applicable CO2

performance rates or state goals under a state plan. In fact, 

the definition of BSER is premised upon shifts in generation 

across sources, particularly shifts from higher- to loweremitting units that result in overall emission reductions. 

However, in the context of these shifts, the extent to which the 

movement of generation may be driven not by the potential to 

capture lower-cost emission reduction but by arbitrage across 

different emission rates will cause inefficiencies in the power 

markets and erode overall emission reductions should be 

Deleted: erode

Commented [A45]: Text edits suggested here 
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minimized. 

The EPA has incorporated elements into the rule that seek 

to minimize double-counting and the distortionary effects that 

could potentially increase emissions. First, states have the 

option to adopt multi-state plans that reflect regional 

interactions while eliminating chances for double counting and 

providing a level playing field for trading of rate-based ERCs 

or mass-based allowances. Second, in the method for rate-based 

plan compliance, the rule provides a general accounting approach 

for adjusting 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 

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 “ready-forinterstate-trading” plans or multi-state plans. These options 

for states working together provide opportunities to enable 

protections against double counting and minimize the presence of 

distortionary effects. 

“Ready-for-interstate-trading” and multi-state plans engage 
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multiple states in the same system for the purpose of trading 

mass-based allowances or issuing and trading rate-based ERCs. 

This allows for efficient implementation of protections against 

double counting provided in state plan requirements, as multiple 

state are participating in the same tracking systems. This is 

particularly useful in the context of rate-based ERC issuance 

and tracking, where it must be ensured that the ERCs being 

generated are unique across rate-based plans. 

This final rule also reduces distortionary effects within 

the context of multi-state plans. It does so by restricting 

states to inter-state trading with equivalently denominated 

mass-based allowances or rate-based ERCs. In a mass-based 

context, all affected EGUs will trade uniform mass-based 

allowances, whether in a “ready-for-interstate-trading” plan or 

multi-state plan. In a rate-based plan context, “ready-forinterstate-trading” states must all adopt as their goal the CO2

emission performance rates for [steam and gas sources] as their 

goal which. This assures that all the participating states are 

issuing ERCs to the two affected fossil EGU sectors at the same 

rates, and that states have equivalent incentives for trading 

ERCs. Similarly, under multi-state plans, the relevant states 

must choose to adopt identical rates, either the CO2 emission 

Commented [A46]: fragment 
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performance rates or a weighted average goal rate based on the 

rate-based goals of the all the states involved. These 

requirements along with a method for calculating a weighted 

average goal rate are specified in Sec.VIII.C.5. 

 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, otherwise there is 

double counting of reductions. 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 

emissions for determining whether a mass-based CO2 emission goal 

is achieved. This means that under a mass-based plan any 

emission reduction measures that are implemented are 

automatically accounted for in reduced stack emissions of CO2
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from affected EGUs, which avoids concerns about counting the 

same mass reductions in two different mass-based states. 

In a rate-based plan, there needs to be an explicit 

adjustment of reported CO2 emission rates from affected EGUs, to 

reflect the measures that substitute low- or zero-emitting 

generation or energy savings for affected EGU generation. States 

with rate-based plans must demonstrate that measures that they 

use to adjust their CO2 emission rate, such as RE and demand-side 

EE, are non-duplicative. The proposal attempted to address this 

issue in part by limiting demand-side EE that states could claim 

to in-state measures. In fact, those in-state measures still 

have an impact outside of the state and 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 the rule’s 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 

its state plan. 

 The general accounting approach for adjusting the CO2

emission rate of an affected EGU inherently accounts for the 
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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 approximating 

exactly how it impacted the regional grid. 

Across states with rate-based plans, the accounting method 

avoids potential double-counting of both components of a CO2

emission rate: CO2 emission reductions and generation. Doublecounting of CO2 emission reductions is prevented because there is 

no explicit adjustment to the numerator of the reported CO2

emission rate that could be redundant to CO2 emission reductions 

already represented in reported CO2 emissions from the affected 
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EGU, such an adjustment could result in double-counting.868

Double-counting of MWhs in the denominator can be avoided 

because it is relatively straightforward to quantify the MWhs 

that the affected EGU is responsible for deploying and add them 

to the denominator, and this method aligns well with the MWhdenominated trading system described in this final rule. As long 

as it is assured that the MWhs of RE and demand-side EE are only 

being claimed by one state, as is outlined in section VIII.K, 

then there is no double-counting of MWh. Therefore, the 

accounting method avoids double counting of both CO2 emission 

reductions and MWhs, the two characteristics of RE and demandside 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 

 

868 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 across the system if an additional 

adjustment was made. 
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particular issue, and many expressed concerns that this use of 

mass-based resources in a rate-based state would result in 

double-counting of emission reductions. 

Commenters provided analyses specifying how two states can 

benefit from the same RE and demand-side EE measures as a result 

of rate- and mass-based plan interactions. Some commenters 

considered this double-counting of emission reductions, and 

requested specific mathematical adjustments of reported 

generation or CO2 emissions from affected EGUs under either ratebased or mass-based state plans in order to eliminate doublecounting. 

The EPA has determined that, in the context of interactions 

among rate-based and mass-based plans, there is not explicit 

double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the 

accounting methods outlined in this final rule. First, as 

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 
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the rate-based state. To the extent that measures that provide 

substitute or avoided generation reduce generation from affected 

EGUs in a mass-based state, the effect of those measures is 

reflected in lower reported CO2 emissions of the mass-based EGUs. 

The CO2 emission reductions reflected in the rate and the mass 

state will necessarily be mutually exclusive, because both are 

based on reported stack emissions. Additionally, the mechanism 

in the mass-based state that is assuring CO2 emission reductions 

is the mass limit, 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 foregone in situations where a source in a 

rate-based state counts the MWh from measures in a mass-based 

state, but the generation from that measure acts solely to serve 

load in the mass-based state. In that scenario, expected CO2

emission reduction actions in the rate-based state are foregone 

as a result of counting MWh that resulted in CO2 emission 
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reductions in a mass-based state. Therefore the EPA is 

restricting the ability of rate-based state to claim low- and 

zero-emitting reductions, such as RE and demand-side EE, located 

in mass-based states. 

While the EPA understands this concern regarding foregone 

reductions, we do not believe it is appropriate to restrict RE 

crediting unilaterally between rate-based and mass-based states. 

Such a restriction could cut some states off from regional RE 

supplies that are assumed in BSER building block 3 and 

incorporated in the CO2 emission performance rates or state ratebased 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 RE MWhs that will 

further enable affected EGUs and states to meet obligations 

under the final rule. Therefore, the EPA has determined that it 

is appropriate for rate-based states to count MWhs from RE 

located in mass-based states, subject to the condition that the 

generation in question was intended to meet electricity load in 

a state with a rate-based plan.869 This maybe apply to some or 

 

869 This does not need to necessarily be the state where the MWh 

of energy generation from the RE measure is used to adjust the 

CO2 emission rate of an affected EGU. 
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all of the generation from an individual RE installation. To 

assure that the RE generation in question meets this condition, 

the EPA is requiring that RE generation from RE installations 

located in a mass-based state can only be counted in a ratebased state if the electricity generated is delivered with the 

intention to meet load in a state with a rate-based plan, and 

was treated as a generation resource used to serve regional load 

that included the rate-based state. This can be demonstrated 

through, for example, the provision of a power delivery contract 

or power purchase agreement in which an entity in the rate-based 

state contracts for the supply of the MWhs in question. The EPA 

is providing flexibility to states regarding the nature of the 

required demonstration, though the state must 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 state 

will need to provide the demonstration of the eligibility of RE 

generation originating in a mass-based state for ERC issuance as 

part of its demonstration that it is achieving the state mass CO2

emission goal for affected EGUs.

 The following are examples of how requirements for a 

Commented [A47]: is this in tension with the remainder of the 

description of the power grid, which observes that electricity cannot 

be differentiated by its generation source, nor directed to a particular 

recipient? 

Formatted: Font: Times New Roman
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demonstration could be established in state plans and used to 

allow RE in a mass-based state to be counted in a rate-based 

state. For an 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 an RE provider 

that seeks the issuance of ERCs to show that load-serving 

entities in the rate-based state have contracted for the 

delivery of the RE generation that occurs in a mass-based state 

to meet load in a rate-based state. Under this approach, an RE 

provider in a mass-based state could submit as part of an 

eligibility application a delivery contract or power purchase 

agreement showing that the generation was procured by the 

utility, and were treated as a generation resource used to serve 

regional load that included the rate-based state. This 

documentation would be sufficient demonstration to allow the RE 

generating resource to meet this additional geographic 

eligibility requirement for the amount of generation in 

question. All quantified and verified RE MWhs submitted for ERC 

issuance would need to be associated with that power purchase 

contract or agreement, and this fact would need to be 

demonstrated in the monitoring and verification reports 

submitted for issuance of ERCs. Formatted: Font: Times New Roman
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 Under a state measures rate-based plan, a state could 

require that any eligible RE 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 

goal for affected EGUs.

 The ability for a rate-based state to count MWhs located in 

a mass-based state under the above conditions is limited to RE.. 

Rate-based states are not allowed to claim demand-side EE or any 

other non-BSER emission reduction measures located in mass-based 

states for ERC issuance. While this limits rate-based sources’ 

access to additional resources, providing that access would 

result in a risk of double counting. Further, unlike RE, there 

is no obligation related to demand-side EE and other non-BSER 

measures incorporated in the CO2 emission performance rates or 

state rate-based CO2 goals which would necessitate facilitating 

access to those resources. This treatment also does not apply to 

fossil-fuel 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, 

Formatted: Font: Times New Roman

Deleted: foregone reductions.
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as is possible under a rate-based plan. 

 As stated earlier, commenters also expressed concern about 

the potential for relative increases in emissions to occur given 

relative differences between sources and states. These 

differences could include states’ goals under either the rateor 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 increasing generation at new fossil sources and expanding 

utilization of existing affected EGU generation in states that 

have less stringent goals, and that this movement of generation 

would result in increased emissions overall. This could 

potentially result in the achievement of performance rates but 

with fewer overall CO2 emissions reductions than projected 

nationally under the proposal—without, therefore, reflecting the 

emission limitation achievable using the best system of emission 

reduction as Section 111(d) requires. 

In section VII.C., the EPA specifies leakage as increased 

emissions that could occur when generation shifts over time from 

affected sources under the rule to unaffected sources. In that 

Commented [A48]: Could EPA provide further explanation of 

here of credit supply dynamics? 

Deleted: .
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section, the agency also acknowledges that there are shifts in 

generation across affected sources that could lead to greater or 

lesser emissions, and explains how the nature of the rate-based 

plan approach minimizes the risk of regulatory arbitrage and

leakage. 

 In particular, the EPA has determined final performance 

rates that serve to reduce relative differences between state 

goals, and thus the risk of leakage between affected sources 

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. 

However, as is discussed in section VII.C, the EPA does see 

a risk of leakage resulting from the movement of generation from 

Deleted: a
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existing affected fossil sources under a mass-based plan to new 

fossil sources. Section VII.C describes how this is a key 

situation in which leakage must be addressed, because leakage is 

a much greater risk under mass-based plans than rate-based 

plans. Under rate-based plans, the emission performance rates 

provide a significant incentive for generation to move from 

higher-emitting to lower-emitting existing sources within and 

across states. This is one way in which reductions are realized 

under the rule. Thus existing lower-emitting EGUS will be 

increasing their utilization, making leakage to new sources much 

less likely. This is possible because existing affected sources 

are allowed to increase their utilization under a rate-based 

plan, where they do not have that opportunity in a mass-based 

context. Therefore, states must address mass-based leakage to 

new sources in their state plans to assure equivalency between 

rate and mass goals. 

The EPA received comments requesting that we address the 

issue of leakage from affected sources to unaffected sources, 

particularly new sources. Commenters suggested various solutions 

to this concern, such as the inclusion of new sources under the 

rule and quantitative adjustments to mass goals. In response to 

this issue, the EPA has sought to give states flexibility in how 

Commented [A49]: Would not gas plants be able to increase 

generation in a mass based state as they have a lower allowance 

obligation than a coal plant? 
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they respond to the risk of leakage and base the solutions on 

what will best suit their unique characteristics and plan 

structure. 

To address the risk of leakage in a mass-based approach and 

ensure equivalency of the approaches, the EPA is requiring that 

states adopting a plan based upon a mass-based statewide CO2

emission performance goal demonstrate that they have addressed 

the risk of leakage in their mass-based state plan and show that 

there is equivalency with a rate-based approach. The following 

options provide sufficient demonstration that leakage has been 

addressed, as long as the agency finds that the demonstration is 

sufficiently specified, justified and supported by relevant 

analysis: 

1) States may choose to include new non-affected fossil EGUs 

under a mass-based state measures plan. This is a method 

that has been adopted by the mass-based systems adopted 

by California and the RGGI participating states. This 

requires the development of a state-wide mass limit of 

sufficient size to cover affected existing sources under 

the existing source mass goal provided in this final rule 

along with sufficient tonnage to cover projected new 

sources. The plan should include all new grid-connected 
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fossil EGUs that meet the applicability standards for 

111(b) sources. States have the option of including a 

wider array of sources if they choose. States will still 

need to demonstrate that affected sources under this rule 

meet the state’s existing source mass goal. The 

requirements for mass-based plans with broader source 

coverage and other flexibilities are discussed in section 

VIII.J.2.c. The plan must also meet all of the 

requirements for the state measure plan approach 

specified in Section VIII.C.3. 

2) States may choose to use allocation methods that address 

generation growth. These allocation approaches should be 

specified in state plans as part of the provisions for 

state allocation of allowances required under a massbased plan approach (see Section VIII.J.2.a). The state 

should also provide a demonstration of how the specified 

allocation method will provide sufficient incentive to 

counteract leakage and ensure equivalency with a ratebased approach. 

We are providing two examples of allocation approaches 

that can address generation growth and leakage to new 

sources: updating output-based allocations and allowance 
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set-asides that target EE and RE. Under the first 

example, updating output-based allocations, some of the 

total allowances within each mass-based state are 

allocated to existing generation, in part, on its level 

of electricity generation in a recent period or periods. 

Therefore, the total allocation to an EGU that is 

eligible to receive allowances from the set-aside is not 

fixed, but instead depends on its generation. Under this 

approach, each eligible EGU may get a larger allowance 

allocation if it generates more. Therefore, eligible EGUs 

will want to generate more in order to receive more 

allowances, making them more competitive with new units 

than they would be in this absence of this approach. 

This can be implemented through the creation of a setaside that reserves a subset of the total allowances 

available to sources, and distributes them based upon the 

criteria described above. Because the total number of 

allowances is limited, this allocation approach will not 

exceed the overall mass-based CO2 emission performance 

goal. Instead, it merely modifies the distribution of 

allowance allocation in a manner designed to mitigate 

emission leakage. 

Deleted: an eligible EGU based

Commented [A50]: We recommend allocations to all existing 

generation, or all existing generation emitting less than the state’s 

blended emission rate, as it will have the intended effect of 

mitigating leakage while not creating a market effect that would 

disincentivize existing zero carbon generation 
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Another example of an allocation strategy is a setaside of allowances to be allocated to providers of 

incremental RE or demand-side EE. The increased 

availability of RE generation can serve as another source 

of generation to satisfy an increase in electricity 

demand. Increased demand-side EE will reduce the demand 

growth that sources need to meet. Therefore increased RE 

and demand-side EE, supported by a dedicated set-aside, 

can also serve to address leakage. 

These two different types of set-asides can complement 

each other, as the updating output-based allocations 

assure room for lower-emitting affected sources to grow 

to meet demand, complemented by increased RE generation. 

More demand-side EE can reduce the demand that needs to 

be met, moderating the extent to which the updating 

allocations are needed for affected sources to increase 

emissions. 

3) Finally, a state can provide a demonstration that leakage 

will not occur without implementing any of the additional 

strategies above, due to unique reasons such as the 

presence of existing state policies addressing leakage or 

unique characteristics of the state and its power sector 
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that will counteract leakage. This demonstration must be 

supported by credible analysis. The EPA will determine if 

the state has provided a sufficient demonstration that 

leakage has already been addressed to ensure equivalency 

with a rate-based approach, or if additional action is 

required as part of the state plan. 

Finally, 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, 

and this could also be a source of increased overall emissions. 

They noted that RE siting would thus not occur in the most 

optimal locations. The commenters assumed that zero-emitting 

credits are denominated in mass units by multiplying the number 

of MWh by some emission rate: either the state goal rate, the 

current state emission rate, a regional emission rate, or a 

calculated marginal rate. If those rates were higher in any 

states, zero-emitting MWhs would create more mass-denominated 

credits in those states, and thus RE and demand-side EE would be 

more valuable. 

 The incentive to target the location of zero-emitting 

generation or energy savings between states based on variation 
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in its emission reduction value has been minimized by the nature 

of the accounting method finalized in this rule. As explained 

above regarding the general accounting approach and the trading 

framework, we are adjusting rates using calculated MWhs, not 

based upon an emission reduction approximation as commenters 

outlined above. Not only does the method allow emission 

reductions to be accounted for as they occur across the grid, 

but it means the ERCs being traded across states represent one 

MWh of zero-emitting generation in whatever state it originated, 

and its value is unaffected by any emission rate associated with 

its state of origin. Thus, the finalized accounting and trading 

methods minimize the relative incentives for generating zeroemitting ERCs in a particular state based upon the rates that 

apply to that state. 

IX. 

IX. Community Considerations and Environmental Justice 

As described in the Executive Summary, climate change is an 

environmental justice issue. Low-income communities and 

communities of color already overburdened with pollution are 

also likely to be disproportionately affected by the impacts of 

climate change. This rulemaking will provide broad benefit to 

communities across the nation, as its purpose is to reduce 
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greenhouse gases, the most significant driver of climate change. 

While addressing climate change will provide broad benefits, it 

is particularly beneficial to low-income populations and some 

communities of color (in particular, populations defined jointly 

by ethnic/racial characteristics and geographic location) where 

people are most vulnerable to the impacts of climate change (a 

more robust discussion of the impacts of climate change on 

overburdened communities is provided in the Executive Order 

12898 section XII.J of this preamble). While climate change is a 

global phenomenon, the adverse effects of climate change can be 

very localized, as impacts such as storms, flooding, droughts, 

and the like are experienced in individual communities. 

This rule will bring other important benefits to 

communities across the nation. The changes in electricity 

generation that will result from this rule will further benefit 

communities by reducing existing air pollution that directly 

contributes to adverse localized health effects. This benefit 

will be achieved through the rulemaking because the electric 

generating units that emit the most greenhouse gases also have 

the highest emissions of conventional pollutants, such as SO2, 

NOX, fine particles, and HAPs. These pollutants are known to 

contribute to adverse health outcomes, including the development 

Deleted: HAP
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of heart or lung diseases, such as asthma and bronchitis, 

increased susceptibility to respiratory and cardiac symptoms, 

greater numbers of emergency room visits and hospital 

admissions, and premature deaths.870 The EPA expects that the 

reductions in utilization of higher-emitting units likely to 

occur during the implementation of state plans will produce 

significant reductions in emissions of conventional pollutants, 

particularly in overburdened communities. Further, this 

rulemaking complements other actions already taken by the EPA to 

reduce conventional pollutant emissions and improve health 

outcomes for overburdened communities. 

While the agency expects overall emission decreases as a 

result of this rulemaking, we recognize that certain EGUs may 

operate more frequently. To the extent that we project increases 

in utilization as a result of this rulemaking, we expect these 

increases to occur generally in lower-emitting NGCC units, which 

have minimal or no emissions of SO2 and HAP, lower emissions of 

particulate matter, and much lower emissions of NOX compared to 

higher-emitting steam units. As described below, the EPA intends 

to assess any emissions increases that may result from plan 

 

870 Six Common Air Pollutants. 

http://www.epa.gov/oaqps001/urbanair/ 
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implementation and to work with states to mitigate adverse 

impacts, if any, in overburdened communities. 

In addition to the many positive anticipated health 

benefits of this rulemaking, it also will increase the use of 

clean energy and will encourage energy efficiency. These changes 

in the electricity generation system, which are already 

occurring but may be accelerated by this program, are expected 

to have other positive benefits for communities. The electricity 

sector is, and will continue to be, investing more in RE and EE. 

The construction of renewable generation and the implementation 

of energy efficiency programs such as residential weatherization 

will bring investment and employment opportunities to the 

communities where they take place. It is important to ensure 

that all communities share in these benefits. And while we 

estimate that the benefits of this program will greatly exceed 

its costs (as noted in the RIA for this rulemaking) it is also 

important to ensure that to the extent that there are increases 

in electricity costs, that those do not fall disproportionately 

on those least able to afford them. 

EPA has engaged with community groups throughout this 

rulemaking and we received many comments on the issues outlined 

above from community groups, environmental justice 

Deleted: invest
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organizations, faith-based organizations, public health 

organizations, and others. In this final rulemaking we address 

many of the concerns that were raised. One example is that 

commenters are concerned about the health, economic, and 

environmental impacts of climate change, but also want to ensure 

that the benefits of this rulemaking are shared fairly and that 

low income communities are not adversely affected by the 

increased costs of electricity. In this section, we respond to 

these concerns. 

We are working with our federal partners to make sure that 

states and communities have information on federal resources 

available to assist communities. We describe these resources 

below, as well as resources that the EPA will be providing to 

assist communities in accessing EE/RE and financial assistance 

programs. In our discussion below we also provide models of 

programs that other states are currently using to assist 

communities in accessing available resources that states could 

use when developing their plans. 

Finally, and importantly, we recognize that communities 

must be able to participate meaningfully in state plan 

development. In this section, we discuss the requirements in the 

final rule for states, as they develop their plans, to provide 
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opportunities for public involvement, and resources available to 

states and communities to enhance the success of the public 

process. 

A. Proximity Analysis 

The EPA is committed to assisting states and communities 

develop plans that ensure there is no disproportionate, adverse 

impact on overburdened communities. To provide information 

fundamental to beginning that process, the EPA has conducted an 

analysis for this final rulemaking that summarizes demographic 

data on the communities located near power plants, which we 

refer to as a proximity analysis.871 The EPA understands that, in 

order to prevent disproportionate, adverse human health or 

environmental effects on these communities, both states and 

communities must have information on the communities living near 

facilities, including demographic data, and that accessing and 

using census data files requires expertise that some community 

groups may lack. Therefore, the EPA used census data from the 

American Community Survey (ACS) 2008-2012 to conduct a proximity 

analysis that can be used by states and communities as they 

develop state plans and as they later assess the final plans’ 

 

871 The proximity analysis was conducted using data that is used to 

update the EPA’s environmental justice mapping and screening tool, 

EJSCREEN). 

Formatted: Highlight
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impacts. The analysis and its results are presented in the EJ 

Screening Report for the Clean Power Plan, which is located in 

the docket for this rulemaking at EPA-HQ-OAR-2013-0602. 

The proximity analysis provides detailed demographic 

information on the communities located within a 3-mile radius of 

each affected power plant in the United States. Included in the 

analysis is the breakdown by percentage of community 

characteristics such as income and minority status. The analysis 

shows a higher percentage of communities of color and low-income 

communities living near power plants than national averages. It 

is important to note that the impacts of power plant emissions 

are not limited to a 3-mile radius and the impacts of both 

potential increases and decreases in power plant emissions can 

be felt many miles away. Still, being aware of the 

characteristics of communities closest to power plants is a 

starting point in understanding how changes in the plant’s air 

emissions may affect the air quality experienced by some of 

those already experiencing environmental burdens. 

Although overall there is a higher fraction of communities 

of color and low-income populations living near power plants 

than national averages, there are differences between rural and 

urban power plants. There are many rural power plants that are 
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located near small communities with high percentages of lowincome populations and lower percentages of communities of 

color. In urban areas, nearby communities tend to be both lowincome communities and communities of color. In light of this 

difference between rural and urban communities proximate to 

power plants and in order to adequately capture both the lowincome and minority aspects central to environmental justice 

considerations, we will use the term “overburdened” when 

referring to these communities. Our intent is for this term to 

be understood in an expansive sense, in order to capture the 

full scope of communities, including tribal communities most 

often located in rural areas, which are central to our 

environmental justice and community considerations. 

As stated in the Executive Order 12898 discussion located 

in section XII.J of this preamble, the EPA believes that all 

communities will benefit from this final rulemaking because this 

action directly addresses the impacts of climate change by 

limiting GHG emissions through the establishment of CO2 emission 

guidelines for existing affected fossil fuel-fired power plants. 

The EPA also believes that the information provided in the 

proximity analysis will promote engagement between overburdened 

communities and their states and will be useful for states as 
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they begin developing their plans. In addition to providing the 

proximity analysis in the docket of this rulemaking, the EPA 

will disseminate the proximity analysis to states and will make 

it publicly available on its EPA Community Climate Protection 

Portal of the Clean Power Plan Website. Furthermore, the EPA has 

also created an interactive mapping tool that illustrates where 

power plants are located and provides information on a state 

level. This tool is available at: 

http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/. 

Additionally, the EPA encourages states to conduct their 

own analyses of community considerations when developing their 

plans. Each state is uniquely knowledgeable about its own 

communities and well-positioned to consider the possible impacts 

of plans on overburdened communities within its state. 

Conducting state-specific analyses would not only help states 

assess possible impacts of plan options, but it would also 

enhance a state’s understanding of the means to engage these 

communities that would most effectively reach them and lead to 

valuable exchanges of information and concerns. A state 

analysis, together with the proximity analysis conducted by the 

EPA, would provide a solid foundation for engagement between a 

state and its overburdened communities. 

Formatted: Highlight
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B. Such state-specific analyses need not be resource-intensive 

to be effective. An examination of the options a state is 

considering for its plan, and any projections of likely 

resulting increases in power plant emissions affecting lowincome populations, minority populations, or tribal 

communities, would be informative for communities. The 

analyses could include available air quality monitoring 

data and information from air quality models, and, if 

available, take into account information about local health 

vulnerabilities such as asthma rates or access to 

healthcare. Alternatively, a simple analysis may consider 

expected EGU utilization in geographic proximity to 

overburdened communities. The EPA will provide states with 

information on its publicly available environmental justice 

screening and mapping tool, EJ SCREEN, which they may use 

in conducting a state-specific analysis. The EPA will also 

provide states with resources containing examples of 

analyses that other states have conducted to examine the 

impacts of their programs on overburdened communities. 

Community Engagement in State Plan Development 

In sections VIII.D-E of this preamble, the EPA notes that 

states need to engage meaningfully with communities and other 

Deleted: exhaustive.
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stakeholders during the initial and final plan submittal 

processes. The EPA envisions meaningful engagement to include 

outreach to overburdened communities, sharing information and 

soliciting input on state plan development and on any 

accompanying assessments such as those described above, and 

selecting methods for engagement to support communities’ 

involvement at critical junctures in plan formulation and 

implementation. This engagement also includes providing the 

public the opportunity to comment on the state’s initial 

submittal and responding to significant comments received, 

including comments from overburdened communities, as well as 

conducting a public hearing and responding to comments before a 

final state plan is submitted. Additionally, the EPA is 

encouraging that states conduct outreach meetings, which could 

include public hearings or listening sessions, before the 

initial plan is submitted. The EPA also encourages states to 

provide background information about their proposed final state 

plan or their initial state plan in the appropriate languages in 

advance of their public hearing and at their public hearing. 

Additionally, the EPA recommends that states provide translators 

and other resources at their public hearings, to ensure that 

members of the public can provide oral feedback. 
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For states submitting an initial plan submittal rather than 

a final plan at the 13 month deadline, the final rule requires 

that states must provide information about the community 

engagement they have undertaken and the means by which they 

intend to involve communities and other stakeholders as they 

develop their final plan. Furthermore, as noted in section 

VIII.E of this preamble, in determining if states are eligible 

for a 2-year extension for submission of final plans, the rules 

require that states demonstrate how they are meaningfully 

engaging overburdened communities and other interested 

stakeholders as part of their public participation process. The 

EPA consulted its May 2015, Guidance on Considering 

Environmental Justice During the Development of Regulatory 

Actions, when crafting this rulemaking and recommends that 

states consult it to assist them in engaging meaningfully with 

overburdened communities.872 Additionally, states in their 

initial plan submittal and 2017 update must show how they 

identified overburdened communities with whom they are engaging 

as they develop their plans. Some suggested actions that states 

 

872 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 

Deleted: In the 

Formatted: Highlight

Formatted: English (United States)

Formatted: English (United States)

Formatted: English (United States)

Formatted: English (United States)
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could take to demonstrate that they are actively engaging the 

public, including conducting meaningful engagement with 

overburdened communities, are outlined in section VIII.E of this 

preamble. Additionally, as outlined in section VIII.D of this 

preamble, the final plan submitted by states should include an 

overview of the public hearing(s) conducted and information on 

how the state ensured that the hearing(s) were accessible to 

stakeholders including overburdened communities. 

The EPA is committed to supporting states in effectively 

engaging with overburdened communities as they develop and 

implement their plans. The EPA will provide training and other 

resources throughout the implementation process that will assist 

states and communities in understanding plan requirements and 

options for plan development. These trainings will be a 

continuation of those that the EPA has already conducted with 

communities and states both pre- and post-proposal. The EPA will 

reach out to a wide variety of community stakeholders, including 

groups representing overburdened communities, faith-based 

organizations, academic organizations working with communities, 

affordable housing advocates, public health professionals, 

public health organizations, and other community stakeholders. 

C. Providing Communities with Access to Additional Resources 
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In addition to providing resources to states, the EPA 

encourages states to be aware of existing efforts undertaken by 

other states aimed at providing overburdened communities access 

to financial and technical assistance programs for EE and RE, 

and to consider similar approaches that may make sense for their 

own states. 

One example of such a program is the Maryland EmPOWER Low 

Income Energy Efficiency Program (LIEEP).873 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.).874 Funding for this program is provided by 

EmPOWER Maryland partners: Baltimore Gas and Electric, Southern 

Maryland Electric Cooperative, Delmarva Power, Allegheny Energy 

and Pepco.875 This program is available to both homeowners and 

renters.876 Additionally, the Maryland Department of Housing 

 

873 EmPOWER Maryland Low Income Energy Efficiency Programs 

(LIEEP). 

http://www.mdhousing.org/website/Programs/lieep/Default.aspx.

874 Ibid. 875 Ibid. 876 Ibid. 
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provides low-income families with home heating bill assistance 

and furnace repairs and replacements through the Maryland Energy 

Assistance Program (MEAP).877 Maryland’s Electric Universal 

Service Program (EUSP) helps low-income electric customers with 

their electric bills.878

Another example of a program is EmPower New York, which 

provides no-cost energy solutions to low- income populations.879

Currently, there are about 100,000 people that are receiving 

assistance. Both homeowners and renters are eligible to receive 

assistance under this program. The types of assistance available 

includes energy efficiency upgrades (plugging leaks, adding 

installation, replacing inefficient refrigerators and freezers 

and new energy-efficient lighting). Other states, like the State 

of Colorado’s Energy Outreach Colorado program, offer similar 

resources for low-income populations. 880

 As discussed below, there are also many federal programs 

that can help overburdened populations access the benefits of 

 

877 Energy Assistance. 

http://www.dhr.state.md.us/blog/?page_id=4326. 

878 Ibid. 879 EmPower New York. http://www.nyserda.ny.gov/AllPrograms/Programs/EmPower-New-York 

880 Energy Outreach Colorado. http://www.energyoutreach.org/about
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renewable energy, energy efficiency, and the economic benefits 

of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information resources for overburdened communities and states on 

existing federal, state, local, and other financial assistance 

programs to encourage EE/RE opportunities that are already 

available to communities. The 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 overburdened communities gain the 

benefits of this rulemaking by encouraging that states use these 

types of tools in their state plans. The use of these RE/EE 

tools can also overburdened households reduce their electricity 

consumption and bills. 

The EPA recognizes the potential impacts that this 

rulemaking could have on jobs in communities. Therefore, in 

section VIII.G of this preamble, the EPA has outlined that 

states, in designing their state plans, should consider the 

effects of their plans on employment and overall economic 

development to realize the opportunities for economic growth and 

jobs that the plans offer.. To the extent possible, states 
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should try to assure that communities that may be expected to 

experience job losses can also take advantage of the 

opportunities for job growth or otherwise transition to healthy, 

sustainable economic growth (e.g., with regard to delivering 

energy efficiency measures and installing rooftop solar panels). 

Additionally, as part of the resources that we will be providing 

to states and overburdened communities, the EPA will provide 

information on the White House’s POWER Initiative and other 

programs that specifically target economic development 

assistance to communities affected by changes in the coal 

industry and the utility power sector.881 

D. Federal Programs and Resources Available to Communities 

Federal agencies have a history of bringing energy 

efficiency and renewable energy to low-income communities. Some 

examples of federal programs that offer resources for low-income 

communities include: the Department of Energy’s Weatherization 

Assistance Program, Health and Human Service’s Low Income Home 

Energy Assistance Program, the Department of Housing and Urban 

Development’s goal (under the President’s Climate Action Plan) 

of installing 100 megawatts of RE across federally subsidized 

housing by 2020, the Department of Agriculture’s Energy 

 

881 http://www.epa.gov/power/. 
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Efficiency and Conservation Loan Program, and the Environmental 

Protection Agency’s RE-Powering America’s Land Initiative. The 

EPA will be working with these federal partners and others to 

ensure that states and overburdened communities have access to 

information on these programs and their resources. 

E. Multi-pollutant planning and Co-Pollutants 

As outlined in the final Clean Power Plan, states and 

sources have continued obligations to meet all other CAA 

requirements addressing conventional pollutants. Because the CAA 

envisions control of these other pollutants as a continuous 

process (through provisions such as periodic review of the NAAQS 

and residual risk requirements under the MACT program), the EPA 

believes that the Clean Power Plan provides an opportunity for 

states to consider strategies for meeting future CAA planning 

obligations as they develop their plans under this rulemaking. 

Multi-pollutant strategies that incorporate criteria pollutant 

reductions over the planning horizons specific to particular 

states, jointly with strategies for reducing CO2 emissions from 

affected EGUs needed to meet Clean Power Plan requirements over 

the time horizon of this rule, may accomplish greater 

environmental results with lower long-term costs. Such 

strategies may also provide opportunities for states, 

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communities, and affected facilities to consider the most 

effective means of meeting these obligations while limiting or 

eliminating localized emission increases that would otherwise 

affect overburdened communities. Furthermore, this type of 

multi-pollutant approach has been suggested by states and 

sources in past rulemakings as a tool to determine the best 

system of emission reductions. The EPA recommends that states 

consider such strategies in consultation with their communities, 

affected facilities, and other stakeholders. 

 Air quality in a given area is affected by emissions 

from nearby sources and may be influenced by emissions that 

travel hundreds of miles and mix with emissions from other 

sources.882 In the Cross-State Air Pollution Rule the EPA used 

its authority to reduce emissions that significantly contribute 

to downwind exposures. The RIA for the final Cross-State Air 

Pollution Rule anticipates substantial health benefits for the 

population across a wide region. Similarly, the EPA believes 

that, like the Cross-State Air Pollution Rule, this rulemaking 

will result in significant health benefits because it will 

reduce co-pollutant emissions of SO2 and NOx on a regional and 

 

882 76 FR 48348. 
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national basis.883 Although there may be localized increases in 

NOx emissions, such increases would likely be more than offset 

by NOx decreases elsewhere in the region that produce a net 

improvement in ozone and particulate concentrations across the 

area. 

Another effect of the final CO2 emission guidelines for 

affected existing fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs - in particular high 

efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized/and or 

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

demands and evolving energy sources, but the final CO2 emission 

guidelines for affected existing fossil fuel-fired EGUs can be 

expected to cause more such changes. Increased utilization of 

solid fossil fuel-fired units generally would not increase peak 

concentrations of PM2.5, NOx, or ozone around such EGUs to levels 

higher than those that are already occurring because peak hourly 

 

883 76 FR 48347. 

Deleted: Thus,

Commented [A51]: This sentence didn’t seem to quite follow 

the rest of the paragraph – not sure if the suggested edit captures the 

intended meaning 

Deleted: may well
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or daily emissions generally would not change; however, 

increased utilization may make periods of relatively high 

concentrations more frequent. It should be noted that the gasfired sources likely to be dispatched more frequently have very 

low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA 

requirements that directly address the conventional pollutants, 

including federal emission standards, rules included in state 

implementation plans, and conditions in title V operating 

permits, in addition to the guidelines in this final rulemaking. 

Therefore, local (or regional) air quality for these pollutants 

is not likely to be significantly affected. For natural gasfired 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.”884 Because gas-fired 

EGUs emit essentially no mercury, increased utilization will not 

increase methyl mercury concentrations in water bodies near 

these affected EGUs. In studies done by DOE/NETL comparing cost 

and performance of coal-and NGCC-fired generation, they assumed 

SO2, NOX, PM (and Hg) emissions to be “negligible.” Their studies 

 

884 65 FR 79831. 
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predict NOx emissions from a NGCC unit to be approximately 10 

times lower than a subcritical or supercritical coal-fired 

boiler.885 Many, although not all, NGCC units are also very well 

controlled for emissions of NOx through the application of after 

combustion controls such as selective catalytic reduction. 

F. Assessing Impacts of State Plan Implementation 

It is important to the EPA that the implementation of state 

plans be assessed in order to identify whether they cause any 

adverse impacts on overburdened communities. The EPA will 

conduct its own assessment during the implementation phase of 

this rulemaking to determine whether the implementation of state 

plans developed pursuant to this rulemaking and other air 

quality rules are, in fact, reducing emissions and improving air 

quality in all areas, or whether there are localized air quality 

impacts that need to be addressed. Furthermore, the EPA 

recommends that states conduct evaluations of their own to 

determine the impacts of their plans on overburdened 

communities. An example of one such approach to assessing a 

state plan for reducing greenhouse gases is the California Air 

 

885 “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.

Deleted: and 

Commented [A52]: Under other CAA authorities? 
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Resources Board’s (CARB), First Update on the Climate Change 

Scoping Plan: Building on the Framework Pursuant to AB32: The 

California Global Warming Solutions Act of 2006, which outlines 

ongoing evaluations that it will conduct to determine the 

impacts of its programs (throughout the implementation stages) 

on overburdened communities.886 CARB’s Adaptive Management Plan 

for the Cap-and-Trade Program is one particular evaluation, 

which is intended to assess any localized emissions increases 

resulting from the program so that the state can appropriately 

respond.887 The EPA recommends that states consider CARB’s 

approaches and other programs as models for conducting ongoing 

assessments of the impacts of their state plans on overburdened 

communities. The EPA will provide training for states and 

communities on resources that they can use to assess options for 

plan development and implementation that appropriately consider 

localized impacts, especially co-pollutants, as well as training 

on how to develop and carry out these evaluations. 

 

886 First Update on the Climate Change Scoping Plan: Building on the Framework 

Pursuant to AB32: The California Global Warming Solutions Act of 2006. 

http://www.arb.ca.gov/cc/scopingplan/2013_update/first_update_climate_change_

scoping_plan.pdf. May 2014. 887 Adaptive Management Plan for the Cap-and-Trade Regulation. 

http://www.arb.ca.gov/cc/capandtrade/adaptive_management/plan.pdf. October 

2011. 
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 This training will include guidance in accessing the 

publicly available information that sources and states currently 

report that can help with ongoing assessments of state plan 

impacts. For example, unit-specific emissions data and air 

quality monitoring data are readily available. This information, 

together with the assessment that the EPA will conduct in the 

implementation phase of this rulemaking and other analyses that 

states may develop, will enable states and communities to 

monitor any disproportionate emissions that may result in 

adverse impacts and address them. 

G. EPA Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on overburdened communities. Throughout 

the implementation phase of this rulemaking, the agency will 

continue to provide trainings and resources to assist 

overburdened communities and states as they engage with one 

another. Additionally, we will provide states with 

recommendations on best practices for engaging with overburdened 

communities. The EPA, through its outreach efforts during 

implementation, will continue to solicit feedback from 
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overburdened communities and states on topics for which they 

would like additional trainings and resources. 

The EPA will also provide states with resources containing 

examples of analyses that other states have conducted to examine 

the impacts of their programs on overburdened communities, as 

well as information on its publicly available environmental 

justice screening and mapping tool, EJ SCREEN. States are 

encouraged to use this preliminary information as well as other 

available information to conduct their own analyses. As 

described above, the EPA will assess the impacts of this 

rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 

information generated throughout the implementation process, on 

its EPA Community Climate Protection Portal that will be linked 

to this rulemaking’s website (www.epa.gov/cleanpowerplan). In 

addition, the EPA has expanded its set of resources that are 

being developed to help states and overburdened communities 

understand the breadth of policy options and programs that have 

successfully brought EE/RE to overburdened communities. The EPA 

is committed to continuing its engagement with states and 

communities from the beginning of plan development through plan 

implementation. 
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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. 

. 

X. Interactions with Other EPA Programs and Rules 

 

A. Implications for the New Source Review Program 

The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For GHG emissions, the prevention of 
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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 

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 
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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 

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 
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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). 888

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 

 

888 Certain stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements. 

See, e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A 

synthetic minor limitation is a legally and practicably 

enforceable restriction that has the effect of limiting 

emissions below the relevant level and that a source voluntarily 

obtains to avoid major stationary source requirements, such as 

the PSD or title V permitting programs. See, e.g., 40 CFR 

52.21(b)(4), 51.166(b)(4), 70.2 (definition of “potential to 

emit”). 
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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 

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 
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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. 

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 
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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. 

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 
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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.889 The EPA recognizes the importance of assuring that each 

of the rules described below can achieve its intended 

environmental objectives in a commonsense, cost-effective 

manner, consistent with underlying statutory requirements, and 

while assuring a reliable power system. Executive Order 13563, 

 

889 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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“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 

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 
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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 

to an additional year, if it is needed to ensure electricity 

reliability. 

2. Cross-State Air Pollution Rule (CSAPR) Formatted: English (United States)
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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 

became effective October 14, 2014. The 316(b) rule establishes 

new standards to reduce injury and death of fish and other 

Formatted: English (United States)

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aquatic life caused by cooling water intake structures at 

existing power plants and manufacturing facilities.890 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 

authority to establish appropriate entrainment reduction 

 

890 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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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 

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technology-based effluent limitations guidelines and standards 

for the steam electric power generating point source category. 

The current regulations, which were last updated in 1982, do not 

adequately address the toxic pollutants discharged from the 

electric power industry, nor have they kept pace with process 

changes that have occurred over the last three decades. Existing 

steam electric power plants currently contribute 50-60 percent 

of all toxic pollutants discharged to surface waters by all 

industrial categories regulated in the United States under the 

CWA. Furthermore, power plant discharges to surface waters are 

expected to increase as pollutants are increasingly captured by 

air pollution controls and transferred to wastewater discharges. 

The proposed regulation, which includes new requirements for 

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 
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those rules) and, where possible, implement integrated 

compliance strategies. For example, in the proposed SE ELG rule, 

the EPA describes its thinking on how it might effectively 

harmonize the potential requirements of that rule with the 

requirements of the final CCR rule. Because these two rules 

affect similar units and may be met with similar compliance 

strategies, common-sense implementation timeframes were 

established in the CCR final rule so that utilities would not be 

required to make major decisions about CCR units without first 

understanding the implications that such decisions would have 

for meeting the surface water protection requirements of the 

final ELG rule. The EPA is taking into account these new CCR 

requirements for coal ash as it develops the final SE ELG rule. 

The EPA's goal in harmonizing the SE ELG and CCR rules is to 

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. 
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Regarding ozone, the proposal included a discussion of the 

June 6, 2013, proposed implementation rule for the 2008 ozone 

National Ambient Air Quality Standards (NAAQS), addressing the 

statutory requirements for areas EPA has designated as 

nonattainment for the 2008 ozone NAAQS. The final implementation 

rule for the 2008 ozone NAAQS was signed on February 13, 2015, 

and published on March 6, 2015, with an effective date of April 

6, 2015. In general, the 2008 ozone NAAQS implementation rule 

interprets applicable statutory requirements and provides 

flexibility to states to minimize administrative burdens 

associated with developing and implementing plans to meet and 

maintain the NAAQS. The rule establishes due dates for 

attainment plans and clarifies attainment dates for each ozone 

nonattainment area according to its classification based on air 

quality thresholds, with attainment dates starting in July 2015 

through July 2032 depending on an area’s classification. 

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 
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retaining the current standard of 0.075 ppm. Among other things, 

the ozone NAAQS proposal also proposed to retain the current 

indicator, averaging time, and form of the standard and included 

a proposed secondary ozone NAAQS in the 0.065 to 0.070 ppm 

range. 

The proposal also outlined the key implementation 

milestones requiring revised state implementation plans, with 

due dates starting in October 2018 for infrastructure and 

interstate transport SIPs, attainment plans due 2020-21, and 

attainment dates of 2020-37. The EPA is under a court order to 

finalize its review of the ozone NAAQS by October 1, 2015. 

 Some commenters expressed concern with the potential 

impact proposed revisions to the ozone NAAQS could have on state 

planning efforts and affected entities’ ability to comply with 

any potentially new requirements associated with a revised ozone 

NAAQS and those related to the 111(d) 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 
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guidelines (and any other climate regulations) with the 

potential revision to the ozone standard to provide certainty 

and flexibility for states and affected sources. 

While it is premature to speculate about the outcome of the 

ozone NAAQS review and how a more stringent ozone NAAQS may 

impact sources of ozone precursor emissions, including EGUs, we 

believe the planning and compliance timeframes that would follow 

from a revised ozone NAAQS and the timeframes we are finalizing 

today for submittal of the CAA section 111(d) state plans will 

allow considerable time for coordination by states in the 

development of their respective plans, as needed. As stated in 

the proposal, the EPA is prepared to work with states to assist 

them in coordinating their efforts across these planning 

processes. 

Regarding PM2.5 NAAQS implementation, the proposal stated 

that the EPA was developing a proposed implementation rule to 

provide guidance to states on the development of SIPs for the 

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 
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nonattainment areas; determination criteria for Reasonably 

Available Control Measures (RACM) for Moderate areas and Best 

Available Control Measures (BACM) for Serious areas; plans for 

demonstrating reasonable further progress and for meeting 

periodic quantitative milestones; and criteria for reclassifying 

a Moderate nonattainment area to Serious. The EPA is planning to 

finalize the PM2.5 implementation rule in early 2016. 

There are currently only 9 areas designated nonattainment 

for the 2012 PM2.5 NAAQS, with an effective date of April 15, 

2015. Since the attainment plans for these areas must be 

completed and submitted to the EPA in September 2016, we expect 

that the four states with such areas should have already decided 

on their approach to implementing the 2012 PM2.5 NAAQS when they 

begin to develop their plans for implementing the 111(d) 

guidelines, and will be able to coordinate the two. 

Related to the SO2 NAAQS, and as stated in the proposal, the 

SO2 NAAQS was revised in June 2010 to protect public health from 

the short-term effects of SO2 exposure. In July 2013, the EPA 

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 
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that contribute to the monitored levels. The date for attainment 

plans for these areas to be completed and submitted to the EPA 

was April 2015. As such, we expect states with such areas to 

have already decided on their approach to implementing the SO2

NAAQS as they start planning for implementation of the 111(d) 

guidelines, which should allow for coordination and 

consideration of SO2 related air quality measures into their 

111(d) planning. The EPA intends to address the designations for 

all other areas in three separate actions in the future.891 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 

 

891 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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Regional Haze Rule. Soon after these deadlines, some of the same 

affected EGUs may be required to reduce their utilization, 

convert into natural gas-fired facilities, or shut down entirely 

as a result of state 111(d) plans. Some commenters have 

expressed concern that for these affected EGUs, specifically 

those that choose to retire, the capital equipment installed to 

comply with the Regional Haze Rule would likely become stranded 

assets. 

While the EPA is providing considerable flexibility for 

states and sources under the final 111(d) 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. 
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In fact, the EPA already has experience working with states 

to account for these very types of changed circumstances.892 The 

EPA will continue to work with states to explore options for 

integrating compliance requirements across multiple regulatory 

programs, as warranted. 

The EPA believes that CAA section 111(d) efforts and 

actions will tend to contribute to overall air quality 

improvements and thus should be complementary to criteria 

pollutant and regional haze SIP efforts. 

7. Final Rule Flexibilities 

As discussed in Section VIII of this preamble, the EPA is 

providing states flexibility in developing approvable plans 

under CAA section 111(d), including the ability to impose 

 

892 For example, Oregon replaced its BART determination for the 

Boardman Coal Plant with a new requirement that accounted for a 

planned shutdown before the EPA took action on the state’s SIP 

submission (76 FR 12661). Washington similarly replaced its BART 

determination for the TransAlta Centralia Power Plant before the 

EPA took action on the state’s SIP submission (77 FR 72742). 

Oklahoma submitted a SIP revision with a new BART determination 

for the AEP/PSO Northeastern Power Station, which included 

enforceable requirements for reduced utilization and early unit 

retirements, to replace a FIP that had been promulgated by the 

EPA (79 FR 12944). Finally, the EPA finalized a BART 

determination for Unit 3 at the Dave Johnston Power Plant in 

Wyoming that included two compliance options, one of which 

included a federally enforceable retirement date and less costly 

controls.
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source-by-source limitations reflecting the BSER performance 

rates to each affected EGU or to adopt rate-based or mass-based 

emission performance goals, and to rely on a wide range of CO2

emission reduction measures, including measures that are not 

part of the BSER. The EPA is also providing states considerable 

flexibility with respect to the timeframes for plan development 

and implementation, with up to 3 years permitted for final plans 

to be submitted after the GHG emission guidelines are finalized, 

and up to 15 years for all emission reduction measures to be 

fully implemented. The EPA is establishing an 8-year interim

averaging period over which to achieve the full required 

reductions to meet the CO2 performance rates, and this begins in 

2022, more than seven years from the June 18, 2014 date of 

proposal of the rulemaking. The 8-year interim period from 2022 

through 2029, is separated into three steps, 2022-2024, 2025-

2027, and 2028-2029, each associated with its own interim CO2

emission performance rates. 

In light of these broad flexibilities, we believe that 

states will have ample opportunity, when developing and 

implementing their CAA section 111(d) plans, to coordinate their 

response to this requirement with source and state responses to 

any obligations that may be applicable to affected EGUs as a 

Commented [A53]: It might be helpful to add potential for 

states to deploy market-based flexible trading frameworks and/or 

averaging which provided even greater flexibility 
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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.893 We also believe that the 

broad flexibilities in this action will enable states and 

affected EGUs to build on their longstanding, successful records 

of complying with multiple CAA, CWA, and other environmental 

requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

XI. Impacts of the Final Action894 

 

893 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. 

894 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 
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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 

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 

 

choose approaches that shift the balance of co-benefits and 

impacts to match broader state priorities. 

Formatted Table

Formatted Table

Formatted Table
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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 

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, 
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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 

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. 
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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 

insufficient to draw a causal connection between GHG emissions 
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and effects on the species in its habitat.895 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 question896 and, based 

on air quality modeling of potential environmental effects, 

concluded that “EPA knows of no modeling tool which can link 

 

895 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). 

896 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). 
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Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 

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 
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listed species, the EPA must consult under the ESA on this 

aspect of the rule. The EPA is also aware of certain questions 

posed by a Member of the U.S. House of Representatives to FWS 

regarding potential effects of the rule on the Big Bend Power 

Station located in Florida, which discharges effluent that 

provides a warm water refuge for manatees.897 

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 

 

897 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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cannot predict with reasonable certainty where such measures may 

take effect or which measures may be adopted. It is not clear, 

for instance, whether a particular implementation plan will 

call, if at all, for increased reliance on wind power, as 

opposed to solar power, or on some other form of low or zero 

carbon emitting generation. It is also entirely uncertain how a 

future implementation plan for a particular state might affect, 

if at all, operations at a specific facility. 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 
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actions based on potential future speculative effects.898 These 

are precisely the types of speculative future activities and 

effects at issue here.899 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? 

 

898 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 

(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). 

899 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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 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] 

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 
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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. 

 These figures reflect the EPA’s illustrative modeling that 

presumes policies that lead to generation shifts and growing use 

of demand-side energy efficiency and renewable electricity 

generation out to 2029. If states make different policy choices, 

impacts could be different. For instance, if states implement 

renewable and/or demand-side energy efficiency policies on a 

more aggressive time-frame, impacts on natural gas and 

electricity prices would likely be less. Implementation of other 

measures not included in the BSER calculation or compliance 

modeling, such as nuclear uprates, transmission system 

improvements, use of energy storage technologies or retrofit 

CCS, could also mitigate gas price and/or electricity price 

impacts. 
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 Energy market impacts from the guidelines are discussed 

more extensively in the RIA found in the docket for this 

rulemaking. 

D. What are the compliance costs?

 The compliance costs of this final action are represented 

in this analysis as the change in electric power generation 

costs between the base case and the final rule in which states 

pursue a distinct set of strategies beyond the strategies taken 

in the base case to meet the terms of the final guidelines. The 

compliance costs estimates include cost estimates for demandside energy efficiency. The compliance assumptions – and, 

therefore, the projected compliance costs - set forth in this 

analysis are illustrative in nature and do not represent the 

full suite of compliance flexibilities states may ultimately 

pursue. The illustrative analysis is designed to reflect, to the 

extent possible, the scope and the nature of the final 

guidelines. However, there is considerable uncertainty with 

regards to the precise measures that states will adopt to meet 

the final requirements, because there are considerable 

flexibilities afforded to the states in developing their state 

plans. 
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 The incremental cost is the projected additional cost of 

complying with the guidelines in the year analyzed and includes 

the amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of demandside 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 

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 
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delivered natural gas prices are projected to increase/decrease 

roughly [X] percent in 2020, increase/decrease [X] percent in 

2025, and increase/decrease [X] percent in 2030 under the final 

guidelines, on a nationwide average basis. The average delivered 

coal price to the utility power sector is projected to 

increase/decrease about [X] percent in 2020, increase/decrease 

[X] percent in 2025, and increase/decrease [X] percent in 2030 

under the final guidelines, on a nationwide average basis. 

Retail electricity prices are projected to increase/decrease [X] 

percent in 2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] in 2030 on an average basis across the 

contiguous U.S. Under the final guidelines, the EPA projects [X] 

GW of additional coal-fired generation may be uneconomic to 

maintain and may be removed from operation by 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 
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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 

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. 
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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 

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 
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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. 

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 

Formatted: Highlight
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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 

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] 
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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 

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 

Monetized 

Health Cobenefits 

Monetized 

Health Cobenefits 

Formatted Table
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(thousands 

of short 

tons) 

(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]

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]

Formatted Table

Formatted Table
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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 

chemical composition, are equally potent in causing premature 

Formatted Table

Formatted Table
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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.900 We refer to these estimates, which were developed 

 

900 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department 

of Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy Council, 
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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 

 

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). Available at: http://[X].
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2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)901 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).902 

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 

 

901 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.

902 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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of the SC-CO2 estimates, and the process by which the SC-CO2

estimates were derived. Many but not all commenters were 

supportive of the SC-CO2 and its application to this rulemaking. 

Commenters also provided constructive recommendations for 

potential opportunities to improve the SC-CO2 estimates in future 

updates. Many of these comments were similar to those that OMB’s 

Office of Information and Regulatory Affairs received in 

response to a separate request for public comment on the 

approach used to develop the estimates. After careful evaluation 

of the full range of comments submitted to OMB, the interagency 

working 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 
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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 

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 

$130 per metric ton of CO2 emissions in the year 2020 (2011$).903

The first three values are based on the average SC-CO2 from the 

 

903 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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three IAMs, at discount rates of 5, 3, and 2.5 percent, 

respectively. The SC-CO2 value at several discount rates are 

included because the literature shows that the SC-CO2 is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

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 
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the literature, such as ocean acidification or potential tipping 

points, for various reasons, including the inherent difficulties 

in valuing non-market impacts and the fact that the science 

incorporated into these models understandably lags behind the 

most recent research. Nonetheless, these estimates and the 

discussion of their limitations represent the best available 

information about the social benefits of CO2 emission reductions 

to inform the benefit-cost analysis. As previously noted, the 

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 
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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 BenMAP904 to calculate 

average regional benefit-per-ton estimates using the health 

impact assumptions used in the PM NAAQS RIA905 and Ozone NAAQS 

RIAs.906,907 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 

 

904 http://www.epa.gov/airquality/benmap/index.html 905 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>. 

906 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>.

907 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>. 

Formatted: Font: Times New Roman, Complex Script Font:

10 pt

Formatted: Font: Times New Roman, Complex Script Font:

10 pt
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standards.908 All benefit-per-ton estimates reflect the 

geographic distribution of the modeled emissions for the 

proposed standards, which may not exactly match the emission 

reductions in this final rulemaking, and thus they may not 

reflect the local variability in population density, 

meteorology, exposure, baseline health incidence rates, or other 

local factors for any specific location. More information 

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 

 

908 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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location and magnitude of their impact on PM2.5 concentrations, 

which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

statistical life used to value reductions in premature 

mortality. For PM2.5, we use two key empirical studies, one based 

on the American Cancer Society cohort study909 and one based on 

the extended Six Cities cohort study.910 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 

 

909 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. 

910 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970. 
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premature mortality (Roman et al., 2008)911 as a characterization 

of uncertainty regarding the PM2.5-mortality relationship. 

For the ozone co-benefits, we present the results as a range 

reflecting benefit-per-ton estimates which use several different 

concentration-response functions for mortality, with the lower 

end of the range based on a benefit-per-ton estimate using the 

function from Bell et al. (2004)912 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

(2005).913 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,914 which evaluated the substantial body of 

 

911 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. 

912 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. 913 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. 914 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 
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published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available,915 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule. As a 

 

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. 

915 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines. 
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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 

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 
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emission reductions for the illustrative analysis of the final 

standards under a set of reasonable assumptions. This analysis 

does not include the type of detailed uncertainty assessment 

found in the 2012 PM2.5 National Ambient Air Quality Standard 

(NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air 

quality input and monitoring data to conduct a complete benefits 

assessment. In addition, using a benefit-per-ton approach adds 

another important source of uncertainty to the benefits 

estimates. The 2012 PM2.5 NAAQS benefits analysis provides an 

indication of the sensitivity of our results to various 

assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for the final standards. 

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket. 
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XII. Statutory and Executive Order Reviews 

Additional information about these Statutory and Executive 

Orders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review, and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

This final action is an economically significant regulatory 

action that was submitted to the OMB for review. Any changes 

made in response to OMB recommendations have been documented in 

the docket. The EPA prepared an analysis of the potential costs 

and benefits associated with this action. This analysis, which 

is contained in the “Regulatory Impact Analysis for Clean Power 

Plan Final Rule” (EPA-452/R-15-003, July 2015), is available in 

the docket and is briefly summarized in section XI of this 

preamble. 

 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 

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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 

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 
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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 

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 
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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 

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
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[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 

Final Guidelines, 2030 

Formatted Table
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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. 

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. 
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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)916 and 

co-benefits from reducing direct exposure to SO2, NOx and 

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

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

 

916 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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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 Tribal Authority Rule (TAR), but 

not the obligation, to apply to the EPA for Treatment as State 

(TAS) for purposes of a CAA section 111(d) plan and, if approved 

by the EPA, to establish a CAA section 111(d) plan for its area 

of Indian country. To date, no tribe has requested or obtained 

TAS eligibility for purposes of a CAA section 111(d) plan. For 

areas of Indian country with affected EGUs where a tribe has not 

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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 

promulgation) is estimated to be a range of 529,000 to 859,000 
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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 54,900 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 
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when states take subsequent action to maintain and/or 

achieve the NAAQS through their state implementation plans. See 

American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. 

Cir. 1999) (NAAQS do not have significant impacts upon small 

entities because NAAQS themselves impose no regulations upon 

small entities). 

Nevertheless, the EPA is aware that there is substantial 

interest in the rule among small entities and, as detailed in 

section III.A of the preamble to the proposed carbon pollution 

emission guidelines for existing EGUs (79 FR 34845-34847; June 

18, 2014) and in section II.D of the preamble to the proposed 

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)
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This action does not contain an unfunded mandate of $100 

million or more as described in UMRA, 2 U.S.C. 1531–1538, and does 

not significantly or uniquely affect small governments. The 

emission guidelines do not impose any direct compliance 

requirements on EGUs located in states, U.S. territories or areas 

of Indian country. As explained in section XII.B above, the rule 

also does not impose specific requirements on tribal governments 

that have affected EGUs located in their area of Indian country. 

The rule does impose specific requirements on state and U.S. 

territory governments that have affected EGUs. Specifically, 

states and U.S. territories are required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 

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 
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governments to which rule requirements apply are not considered 

small governments. 

In light of the interest among governmental entities, the 

EPA conducted outreach with national organizations representing 

state and local elected officials and U.S. territory and tribal 

governmental entities while formulating the provisions of this 

rule. Sections III.A and XI.F of the preamble to the proposed 

carbon pollution emission guidelines for existing EGUs (79 FR 

34845-34847; June 18, 2014) and sections II.D and VI.F of the 

preamble to the proposed carbon pollution emission guidelines 

for existing EGUs in areas of Indian Country and U.S. 

Territories (79 FR 65489; November 4, 2014) describes the 

extensive stakeholder outreach the EPA has conducted on setting 

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 

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provide the funds necessary to pay those costs. As discussed in 

the Supporting Statement found in the docket for this 

rulemaking, the development of state plans will entail many 

hours of staff time to develop and coordinate programs for 

compliance with the rule, as well as time to work with state 

legislatures as appropriate, to develop a plan submittal. 

Consistent with this determination, the EPA provides the 

following federalism summary impact statement.

The EPA consulted with state and local officials early in 

the process of developing the proposed action to permit them to 

have meaningful and timely input into its development. As 

described in the Federalism discussion in the preamble to the 

proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state 

and local officials in the process of developing the proposed 

standards for newly constructed EGUs. This outreach addressed 

planned actions for new, reconstructed, modified and existing 

sources. The EPA invited the following 10 national organizations 

representing state and local elected officials to a meeting on 

April 12, 2011, in Washington DC: (1) National Governors 

Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) 
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U.S. Conference of Mayors, (6) National Association of Counties, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 

The National Association of Clean Air Agencies also 

participated. On February 26, 2014, the EPA re-engaged with 

those governmental entities to provide a pre-proposal update on 

the emission guidelines for existing EGUs and emission standards 

for modified and reconstructed EGUs. In addition, as described 

in section III.A of the preamble to the proposed carbon 

pollution emission guidelines for existing EGUs (79 FR 34845-

34847; June 18, 2014), extensive stakeholder outreach conducted 

by the EPA allowed state leaders, including governors, state 

attorneys general, environmental commissioners, energy officers, 

public utility commissioners, and air directors, opportunities 

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. 
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The EPA received comments from over 400 entities representing 

state and local governments. 

Several themes emerged from state and local government 

comments. Commenters raised concerns with the building blocks 

that comprise the best system of emission reduction (BSER), 

including the stringency of the building blocks, and the timing 

of achieving interim CO2 levels. They also identified the 

potential for electric system reliability issues and stranded 

assets due to the proposed timeframe for plan submittals and CO2

emission reductions. In addition, states commented on state plan 

development and implementation topics, including state plan 

approaches, early actions, trading programs, interstate 

crediting for RE, and EPA guidance and outreach. 

Commenters identified overarching concerns regarding the 

stringency of the CO2 goals and the timeframe for achieving 

reductions that encompassed the building blocks, the BSER, and 

associated timing for achievement of interim CO2 levels. State 

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 
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building blocks, the period of time over which measures are 

deployed, and the stringency of emission limitations that those 

measures can achieve in a practical and reasonable cost way. The 

final BSER reflects those refinements. 

To many commenters, the proposal’s 2020 compliance date, 

together with the stringency of the interim CO2 goal, bore 

significant reliability implications. In this final rule, the 

agency is addressing those concerns via adjustments to the 

compliance timeframe (an 8-year interim period that begins in 

2022) and to the approach for meeting interim CO2 emission 

performance rates (a glide path separated into three steps, 

2022-2024, 2025-2027, and 2028-2029), as well as a more gradual 

phase in of the emission reduction expectations. These 

adjustments provide more time for planning, consultation and 

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

choices of compliance strategies. The final rule also retains 

flexibilities presented in the proposal and offers additional 

opportunities, including opportunities for trading within and 

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 

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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 

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 
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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 

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 

Commented [A54]: Would be helpful to here add dicussion of 

the final early action framework 
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number of comments from states and stakeholders about the value 

of EPA support in developing and/or administering tracking 

systems to support state administration of rate-based and massbased emission trading programs. In this final rule, states may 

use trading or averaging approaches and technologies or 

strategies that are not explicitly mentioned in any of the three 

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

achieve the required emission reductions from affected fossilfuel-fired EGUs. In addition, in response to concerns from 

states and power companies that the need for up-front interstate 

cooperation in developing multi-state plans could inhibit the 

development of interstate programs that could lower cost, the 

final rule provides additional options to allow individual EGUs 

to use creditable out-of-state reductions to achieve required CO2

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

The EPA is committed to working with states to provide support 

for tracking of emissions and allowances or credits, to help 

implement multi-state trading or averaging approaches. 

In their comments, many states identified the need for the 

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 
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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 

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 
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to make these resources available via a dedicated website. 

A list of the state and local government commenters has 

been provided to OMB and has been placed in the docket for this 

rulemaking. In addition, the detailed response to comments from 

these entities is contained in the EPA’s response to comments 

document on this final rulemaking, which has also been placed in 

the docket for this rulemaking. 

 As required by section 8(a) of Executive Order 13132, the 

EPA included a certification from its Federalism Official 

stating that the EPA had met the Executive Order’s requirements 

in a meaningful and timely manner when it sent the draft of this 

final action to OMB for review pursuant to Executive Order 

12866. A copy of the certification is included in the public 

version of the official record for this final action.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

This action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. Tribes 

are not required to develop or adopt CAA programs, but they may 

apply to the EPA for treatment in a manner similar to states 

(TAS) and, if approved, do so. As a result, tribes are not 

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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 

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 
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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. 

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 
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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 

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 
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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 

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 
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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 

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 

Commented [A55]: Would it be possible to provide a response 

to these comments or cross-reference the RTC? 

Formatted: Font: Bold, Pattern: Clear
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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. 

These assessments describe how children’s unique 

physiological and developmental factors contribute to making 

them particularly vulnerable to climate change. Impacts to 
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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 

reduction in coal-fired electricity generation as a result of 

this rule. The EPA projects that utility power sector delivered 

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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, 

implementation, and enforcement of environmental laws, 

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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).917 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 

 

917 “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 
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upon the natural environment will likely be affected by the 

degradation of ecosystem goods and services associated with 

climate change. The 2009 Endangerment Finding record also 

specifically noted that Southwest native cultures are especially 

vulnerable to water quality and availability impacts. Native 

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.918

 

918 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. 
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The new assessment literature provides more detailed findings 

regarding these populations’ vulnerabilities and projected 

impacts they may experience. In addition, the most recent 

assessment reports provide new information on how some 

communities of color (more specifically, populations defined 

jointly by ethnic/racial characteristics and geographic 

location) may be uniquely vulnerable to climate change health 

impacts in the United States. These reports find that certain 

climate change related impacts—including heat waves, degraded 

air quality, and extreme weather events—have disproportionate 

effects on low-income populations and some communities of color, 

raising environmental justice concerns. Existing health 

disparities and other inequities in these communities increase 

their vulnerability to the health effects of climate change. In 

addition, assessment reports also find that climate change poses 

particular threats to health, well-being, and ways of life of 

indigenous peoples in the United States. 

As the scientific literature presented above and as the 

2009 Endangerment Finding illustrates, low income populations 

and some communities of color are especially vulnerable to the 

 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.
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health and other adverse impacts of climate change. The EPA 

believes that communities will benefit from this final 

rulemaking because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the 

establishment of CO2 emission guidelines for existing affected 

fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines 

finalized in this rulemaking would reduce other emissions from 

affected EGUs that reduce generation due to higher adoption of 

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,919 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 

 

919 “National Ambient Air Quality Standards for Particulate 

Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 
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effects.920 Therefore, in areas where this rulemaking reduces 

exposure to PM2.5, ozone, and methylmercury, low-income 

populations will also benefit from such emissions reductions. 

The RIA for this rulemaking, included in the docket for this 

rulemaking, provides additional information regarding the health 

and ecosystem effects associated with these emission reductions. 

Additionally, as outlined in the community 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 overburdened communities. The EPA 

consulted its May 2015, Guidance on Considering Environmental 

Justice During the Development of Regulatory Actions, when 

determining what considerations to put in place.921 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. 

 

920 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>. 921 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 

Formatted: English (United States)

Formatted: English (United States)

Formatted: English (United States)

Formatted: English (United States)
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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 1385 of 1486

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. 

 
Page 1386 of 1486

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 federally enforceable state 

or multi-state plan? 

60.5745 What must I include in my final plan submittal? 

60.5750 Can I work with other states to develop a multi-state 

plan? 

60.5755 Can I include existing requirements, programs, and 
Page 1387 of 1486

measures in my plan? 

60.5760 What are the timing requirements for submitting my 

plan? 

60.5765 What must I include in an initial plan submittal in 

lieu 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) 
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Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 Per Net MWh) 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (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? 
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 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 1390 of 1486

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 1391 of 1486

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 paragraphs (a) and (b)? 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 

Deleted: paragraph
Page 1392 of 1486

§ 60.5740 What must my federally enforceable state or multi 

state plan include? 

(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) Identification of affected EGUs. Consistent with § 

60.25(a), you must identify the affected EGUs covered by your 

plan and all affected EGUs in your state that meet the 

applicability criteria in § 60.5805. 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) Emission Standards. You must include an identification 

of all emission standards for each affected EGU according to § 

60.5775, compliance periods for each emission standard according 

to § 60.5770, and a demonstration that the emission standards 

are, when taken together, sufficiently protective to meet the 

applicable CO2 emission performance rates described in § 60.5815. 

Allowance systems are an acceptable form of emission standards 

under this subpart. 
Page 1393 of 1486

(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 step CO2

emission performance rate or CO2 emission goal by 10 percent or 

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) State Measures Backstop. 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, within 18 months 

of the end of the applicable interim step 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 

Commented [A56]: We recommend that this period be 

shortened. 
Page 1394 of 1486

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. 

(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. You must 

include in your plan an identification of all applicable 

monitoring, reporting and recordkeeping requirements for each 

affected EGU and the requirements must be consistent with or no 

less stringent than the requirements specified in § 60.5820.

(5) State Reporting. Description of the process, contents, 

and schedule for state reporting to the EPA about plan 

implementation and progress including information required under 

§ 60.5830. 

(i) You must include in your plan a requirement for a 

report to be submitted by July 1, 2021, that demonstrates that 
Page 1395 of 1486

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 

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 
Page 1396 of 1486

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, each interim step, the final period, and 

each final step, pursuant to § 60.5770. 

(3) You must include a demonstration that the affected EGUs 

covered by the plan are projected to achieve the CO2 emission 

performance rates or CO2 emission goals described in § 60.5815. 

(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 
Page 1397 of 1486

demonstration is required beyond inclusion of the emission 

standards in the plan. 

(ii) If a plan applies rate-based emission standards to 

individual affected EGUs at a 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 

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 the interim period, each interim step, the final period, 

and each final step. 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 adjustments based on use of ERCs in 

compliance demonstrations by affected EGUs, and details about 

the specific anticipated ERCs, including but not limited to, 

anticipated quantities (in MWh) of specific technology-types 
Page 1398 of 1486

(e.g., wind, solar, nuclear), 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) Anticipated electricity demand growth at the state or 

regional level, including the source and basis for these 

estimates; 

(E) Anticipated fuel switching at affected EGUs; 

(F) Heat rate improvements at affected EGUs; 

(G) Demonstration that each emission standard included in 

your plan meets the requirements of §60.5775; and 

(H) 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 period and final periods 

that are equal to or lower than the applicable state mass-based 

CO2 goals specified in table 3 of this subpart. The compliance 

Commented [A57]: If a state is participating in a market, could 

the agency describe how it would generate such projections? 
Page 1399 of 1486

periods in your plan for affected EGUs must align with each 

interim step and final step in your plan. 

(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. 

(ii) You must include the schedule and milestones for the 

implementation of the state measures. If the state measures in 

your plan submittal rely upon measures that do not have a direct 

effect on the emissions measured at a specific affected EGU’s

stack emissions, you must also demonstrate how the minimum 

emission, monitoring and verification (EM&V) requirements listed 

under § 60.5795 that apply to those programs and projects will 

be met. 

(iii) You must demonstrate that the federally enforceable 

emission standards for affected EGUs, if included, and state 

measures, are sufficient to attain the CO2 emission performance 

rates or CO2 emission goal for the interim period, each interim 

Deleted: an

Deleted: EGUs
Page 1400 of 1486

step in that interim period, the final period, and each final 

step in that final period . In addition, you must demonstrate 

that each emission standard included in your plan meets the 

requirements of §60.5775, and each state measure included in 

your plan submittal meets the requirements of §60.5780. 

(iv) You must include a CO2 performance projection of your 

state 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 period and 

the final period: 

(A) A baseline demand and supply forecast as well as the 

underlying assumptions and data sources of each forecast; 

(B) The magnitude of energy and emission impacts from all 

measures included in the plan and applicable assumptions; 

(C) An explanation of the tools and emission quantification 

approaches used in the projection; and 

(D) Underlying emission quantification assumptions. 

(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, 
Page 1401 of 1486

to demonstrate state measures will meet your CO2 emission 

performance rates or the rate-based CO2 emission goal: 

(A) A summary of each affected EGU’s anticipated future 

operation characteristics, including annual generation, CO2

emissions, capacity and capacity factors; 

(B) Planned retirements; 

(C) A detailed description of the zero CO2 emitting demandside energy efficiency (EE) savings and renewable energy (RE) 

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 

Commented [A58]: It might be helpful to describe in the 

preamble text how such forecasts could be done / are already done in 

the context of power company / PUC planning, if that is the case
Page 1402 of 1486

projection. 

(vi) If the state measures in your plan submittal are 

designed to meet mass-based CO2 emission goals, a state must 

demonstrate that the combined 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 

interim period, interim step, final period, and final step. 

(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 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 1403 of 1486

(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 to the EPA 

electronically 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 1404 of 1486

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 1405 of 1486

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 1406 of 1486

 (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 1407 of 1486

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 1408 of 1486

(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 1409 of 1486

(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-based or mass-based emission performance level, 
Page 1410 of 1486

rate-based or mass-based emission standards), including draft or 

proposed legislation and/or regulations. 

(3) An updated comprehensive roadmap with a schedule and 

milestones for completing the 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 step, the 

final period, and each final step according to paragraph (b) of 

this section. You must also include in your plan compliance 

periods for each affected EGU regulated under the plan according 

to paragraphs (c) and (d) of this section. 

(b) Your plan must achieve each state emission performance 

rate required under § 60.5815 over its applicable periods 

according to paragraphs (b)(1) through (3) of this section: 

(1) The interim period. 

(2) Each interim step. 

(3) The final period. 
Page 1411 of 1486

(4) Each final step. 

(c) IThe emission standards for affected EGUs regulated 

under the plan must include the following compliance periods: 

(1) For the interim period, affected EGUs must have 

emission standards that have compliance periods that are no 

longer than each interim step. 

(2) For the final period, EGUs must have emission standards 

that have compliance periods that are no longer than each final 

step. 

(3) Compliance periods for each interim step and each final 

step may take forms shorter than specified in this regulation, 

provided the schedules of compliance collectively end on the 

same schedule as each interim step and final step. 

(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 period for achievement of each state measure 

must be identical to 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 must include the methods by which each emission 

standard meets each of the following requirements in paragraphs 
Page 1412 of 1486

(b) through (f) of this section. 

(b) An affected EGU’s emission standard is quantifiable if 

it can be reliably measured, in a manner that can be replicated. 

(c) An affected EGU’s emission standard is verifiable if 

adequate monitoring, recordkeeping and reporting requirements 

are in place to enable the state and the Administrator to 

independently evaluate, measure, and verify compliance with the 

emission standard. 

(d) An affected EGU’s emission standard is non-duplicative 

with respect to a state plan if it is not already incorporated 

as an emission standard in another state plan unless 

incorporated in multi-state plan.

(e) An affected EGU’s emission standard is permanent if the 

emission standard must be met for each compliance period, or 

unless it is replaced by another emission standard in an 

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 
Page 1413 of 1486

for violations can be identified; 

(4) Each compliance activity or measure is enforceable as a 

practical matter; and 

(5) The Administrator maintains 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 

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 
Page 1414 of 1486

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 

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, non-
Page 1415 of 1486

duplicative, 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. 

(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 
Page 1416 of 1486

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. 

(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 
Page 1417 of 1486

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: 

(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 
Page 1418 of 1486

offset any emission performance deficiency that occurred during 

an exceeded interim step or final step. 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 notify the EPA that your state will need a 

short–term modification of emission standards under a plan for a 

specified affected EGU or EGUs in order to respond to an 

unforeseen, emergency situation that threatens reliability and 

therefore qualifies as a reliability safety valve issue. The EPA 

will consider this reliability safety valve issue 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 shortterm modification, allows modification to emission standards 

under the state plan for an affected EGU or EGUs so that for a 

maximum of 90 days. During that period of time, the EGU or EGUs 

will need to comply with the modified emissions standards under 

the reliability safety valve to respond to this kind of 

reliability concern. The EPA will consider this use of the 

reliability safety valve approved if the notification meets the 

requirements of subsection (1) below. The EPA reserves the right 

to review any such notification, and in the event that the EPA 

finds such notification is improper, the EPA may disallow the 
Page 1419 of 1486

short-term modification and affected EGUs must operate under the 

approved state plan emission standards. A state may use the 

reliability safety valve only once during the final rule 

implementation period. 

(1) To notify the EPA of this short-term modification you 

must submit to the EPA the following: 

(i) A full description of the reliability concern and why 

an unforeseen, emergency situation that threatens the 

reliability requires the affected EGU (or EGUs) to operate under 

modified emission standards from those originally required in 

the plan; 

(ii) A description of how you are 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) Information regarding any system-wide or other 

analysis of the reliability safety valve concern conducted by 

the relevant planning authority, if there is any. 

(2) At the end of the 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 1420 of 1486

(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 to address the reliability issue. 

§ 60.5790 What must I do to meet my plan obligations? 

(a) To meet your plan obligations by requiring either 

emission standards or state specific measures on your affected 

EGUs as specified in § 60.5740, you must demonstrate that your 

affected EGUs are complying with their emission standards and 

you must demonstrate that you are meeting your state measures 

and 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 
Page 1421 of 1486

trading program for your affected EGUs, the state plan must 

include emission standards and requirements that specify the 

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 must 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: 

Where: 

MCO2 = Measured CO2 mass in units of pounds (lbs) summed 

over the compliance period for an affected EGU. 

MWhop = Total net energy output over the compliance 

period for an affected EGU in units of MWh. 

MWhERC = ERC replacement generation for an affected EGU in 

ೀమ಴ெ ∑ ൌ ݁ݐܽݎ ݊݋݅ݏݏ݁݉݅ ݈݅ܽ݊ܿ݁݌݉݋ܿଶܱܥ	 :Deleted

∑ ெௐ௛೚೛ ା∑ ெௐ௛ ಶೃ಴
Page 1422 of 1486

units of MWh (ERCs are denominated in whole 

integers as specified in § 60.5791). 

(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 must 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. EPA will have the sole 

discretion in determining is the alternate components are at 

least as stringent as those in § 60.5791 through § 60.5797.
Page 1423 of 1486

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 

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; 
Page 1424 of 1486

 (5) It is and has been owned by only one person at one 

time; 

 (6) It exists in only one account on a qualified state or 

EPA ERC tracking system; and 

 (7) It was issued to a qualifying ERC generating resource 

that is 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. 
Page 1425 of 1486

§ 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: 

 (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 
Page 1426 of 1486

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? 

 (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 
Page 1427 of 1486

state ERC tracking system must meet the requirements in 

paragraphs (d)(1) through (6) for ERC issuance. 

 (1) Registration. A qualifying ERC generating resource 

registers with the qualified state ERC tracking system pursuant 

to the requirements of paragraph (l) of this section, and an 

independent third party verifier registers with the qualified 

ERC tracking system pursuant to the requirements of paragraph 

(m) of this section. 

 (2) Eligibility approval. A qualifying ERC generating 

resource submits to the qualified ERC tracking system an EM&V 

eligibility application that is 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. 
Page 1428 of 1486

 (4) ERC issuance. 

 (i) Following implementation of the particular activity, 

project or program specified in paragraph (d)(1) of this 

section, an affected EGU or qualifying ERC generating resource 

submits to the qualified state ERC tracking system a postproject EM&V report that is consistent with EPA’s minimum 

criteria set forth in § 60.5795 and reports the MWh of energy 

generation or energy savings attributable to the activity, 

project or program over the specific period and as covered by 

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 

must 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, 
Page 1429 of 1486

determines the number of ERCs that were generated (if any) 

during the specific period covered by the EM&V plan, and issues 

a corresponding amount of ERCs into the generation account of 

the affected EGU or qualifying ERC generating resource. 

 (5) Frequency of ERC issuance. A qualified state ERC 

tracking system must 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 must 

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. 
Page 1430 of 1486

 (g) ERC Transfers. 

 (1) Transfers to/from other qualified ERC tracking systems. 

A qualified ERC tracking system may accept into its tracking 

system ERCs from another qualified ERC tracking system and may 

preclude such transfers. 

 (2) Transfers to/from an EPA ERC tracking system. To 

transfer ERCs to/from an EPA CPP ERC tracking system, the 

qualified state ERC tracking system must be registered for such 

use by the EPA. 

 (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 
Page 1431 of 1486

of qualifying ERCs issued to the qualifying affected EGU or ERC 

generating resource in the prior period. 

 (i) Mechanism to halt issuance. A qualified ERC tracking 

system has mechanisms in place to temporarily or permanently 

halt issuance of specific ERCs, to remove specific ERC 

generating resources from its tracking system, and/or to reject 

the transfer of ERCs that do not meet the requirements of § 

60.5791. 

 (j) ERC Information. A qualified ERC tracking system must 

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 
Page 1432 of 1486

in subsequent compliance periods. 

 (8) Unique ERC serial numbers. 

 (9) Vintage of ERCs, with last quarter and year of 

generation contributing to an accumulated MWh recorded. 

 (10) Parties to each ERC trade, and dates of each ERC 

trade. 

 (11) Date an ERC was surrendered. 

 (12) Date an ERC was retired. 

 (13) In the case of a qualifying ERC generator that is 

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 
Page 1433 of 1486

meter 

 (14) In the case of a qualifying energy saving activity, 

you must have sufficient tracking requirements for 

quantification of the MWh of energy saved. 

 (k) Reports. A qualified ERC tracking system provides at 

least the following reports: 

 (1) EGU Reports. A qualified ERC tracking system commits to 

provide the ability for each ERC holder to obtain reports of 

their account activity that includes the information specified 

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 must 

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 
Page 1434 of 1486

regulation on the qualified state ERC tracking system). The 

qualified state ERC tracking system must provide this 

functionality for as long as this regulation is effective. 

 (3) EPA and state regulator reports. A qualified state ERC 

tracking system must 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 must 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 must 

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 
Page 1435 of 1486

to generate ERCs in compliance with § 60.5791; 

 (3) In the case of a qualifying energy ERC generator annual 

submission of a copy of the qualifying ERC generating resource’s 

U.S. Energy Information Agency’s Annual Electric Generator 

Report Form EIA-860 to the qualified state ERC tracking system, 

or, if the qualifying ERC generating resource generates less 

than 1 MW/year, annual submission of registration data that 

would be included on a Form EIA-860 if that entity was required 

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 
Page 1436 of 1486

assurance plan by an independent third party verifier for 

purpose of compliance with this regulation, a qualified state 

ERC tracking system must enter an agreement with the independent 

third party verifier that requires the verifier to register with 

the qualified state ERC tracking system, and meet the 

requirements of § 60.5797 and § 60.5796 of this subpart. 

 (n) Periodic audits of independent third party verification 

assurance plans. You must audit the qualified ERC tracking 

system no less frequently than annually of the content of a 50 % 

of the verification assurance plans and of at least 50 % of its 

independent third party verifiers]. Each independent third party 

verifier registered with its qualified state ERC tracking system 

must 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-
Page 1437 of 1486

standard practices and guidance documents, and that meets the 

requirements of this section. 

 (b) Each EM&V plan or report must describe the specific 

activity, project or program and identify its location(s) and 

year(s) of installation and subsequently provide notice of any 

of the following: 

(1) A change in energy generation or savings capability of 

the qualifying ERC generating resource, and the date on which 

the change occurred, no later than 30 days from when the change 

is implemented, 

(2) A change to any of the essential generating or savings 

characteristics of the qualifying ERC generating resource, where 

essential generating characteristics shall mean any 

characteristics that affect the eligibility of the qualifying 

ERC generating resource for purpose of compliance with this 

regulation, including the type of qualifying ERC 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 
Page 1438 of 1486

than 10 kW for which metered data are available. For a 

qualifying energy generating resource with a nameplate capacity 

of 10 kW or more, or for a qualifying energy generating resource 

with a nameplate capacity of less than 10 kW for which metered 

data are available, to generate ERCs, its EM&V plan and EM&V 

reports must demonstrate that the requirements in paragraphs 

(d)(1) through (6) are met. 

(1) The generation data was physically measured using a 

revenue-quality meter, which shall mean a meter used by a 

control area operator for financial settlements, or a meter that 

meets the American National Standards Institute No. C12.20., 

Code for Electricity Metering, metering accuracy standards, or a 

meter that meets an alternative equivalent standard that has 

been approved in advance of its use to measure generation for 

purpose of compliance with this regulation by EPA. 

(2) The generating data was measured at the generator’s 

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 
Page 1439 of 1486

aggregated is each less than 150 kW, and units collectively do 

not exceed a total nameplate capacity of 1 MW when aggregated, 

and 

(iii) The generation data are measured by the same type of 

meter. 

(4) The generation data was collected electronically by 

either a MV-90 meter data acquisition system or by pulse 

accumulator readings collected by the control area’s Energy 

Management System and telemetered from the generator to the 

control area operator, and the data was verified through a 

control area energy accounting or settlements process which 

occurs at least monthly. 

(5) The generation data was transmitted by a control area 

operator, and if the control area operator is affiliated with 

the owner or operator of the qualifying energy generating 

resource, a person at the control area operator who is precluded 

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. 
Page 1440 of 1486

(ii) For generators interconnected to transmission systems 

and with on-site loads other than station service drawing 

generation before the metering point, ERCs may be issued for onsite load, if the owner or operator of the qualifying energy 

generating resource can demonstrate that the metering used is 

capable of distinguishing between on-site load and station 

service. 

(e) Criteria for a qualifying energy generating resource 

with a nameplate capacity of less than 10 kW. For a qualifying 

energy generating resource with a nameplate capacity of less 

than 10 kW to generate ERCs, its EM&V plan and EM&V reports must 

demonstrate that the following requirements in paragraphs (e)(1) 

though (6) are met. 

(1) Metered data are unavailable. 

(2) At least 1 MW direct current is generated to the 

distribution or transmission system over a continuous 365 day 

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 
Page 1441 of 1486

generation characteristics, and 

(iv) The generation data are measured by the same 

generation estimating software or algorithms. 

(4) Generation data is measured on at least a monthly basis 

using generation estimating software or algorithms that are 

based on an on-site inspection prior to interconnection and a 

resource study (wind, shading, solar irradiance, depending on 

the resource), or engineering information that takes into 

account the size, age, and type of qualifying energy generating 

resource. 

(5) The generation data was self-reported by the qualifying 

energy resource to its distribution utility and to its 

distribution utility through an electronic internet-based portal 

with software that reports total and hourly generation. 

(6) The generation data serves a load that otherwise would 

have been served by the grid if not for the generator. The ERC 

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 
Page 1442 of 1486

the EM&V plan or report): 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using applicable, 

credible, and rigorous industry-standard practices and guidance 

documents. 

(2) All savings values must be which determined and 

reported in units of gross MWh relative to a specified baseline; 

in cases where gross savings values are not available (e.g., 

randomized control trials), net savings can be reported. 

(3) All savings values determined must be determined on a 

regular basis – at intervals sufficient to credibly document 

annual savings – by application of one or more non-control group 

approaches and/or control group approaches. 

 (4) All savings values assessed using deemed savings must 

be documented in a publicly available database and be reviewed 

and updated at least every 3 years. The database must indicate, 

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, 
Page 1443 of 1486

the adjustment must be based on the lesser of 6 percent of the 

site-level savings or the calculated statewide annual average 

transmission and distribution loss rate expressed as a 

percentage and based on values in the most recent year that is 

published in the US EIA State Electricity Profile. For 

transmission and distribution efficiency measures, MWh savings 

from voltage optimization must be calculated on the basis of 

industry-standard protocols and procedures identified in an EM&V 

plan. 

(7) The duration of EE program or project electricity 

savings must be determined using periodic verification 

assessments, industry-standard persistence studies, deemed 

estimates of effective useful life (EUL), or a combination of 

all three. 

(8) If deemed EUL estimates are used for determining the 

duration of savings, then zero savings must be assumed at the 

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. 
Page 1444 of 1486

(g) EM&V plans for demand-side EE must describe and 

document the following: 

(1) The baseline energy usage conditions, with clear 

documentation and discussion of the rationale, applicability, 

and relevant data sources, protocols, and guidance documents 

used for defining the common practice baseline (CPB). 

(2) The selected EM&V method, associated assumptions, and 

data sources used to quantify savings from demand-side EE. 

(3) How major changes in independent variable conditions 

that affect energy consumption and savings estimates will be 

analyzed. 

(4) How the initial installation of EE will be verified 

within the first year of implementation for EE program 

categories that involve the installation of identifiable 

measures. 

(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 
Page 1445 of 1486

programs do not separately claim savings from the same EE 

project or measure. 

(9) How the relevant protocols, guidelines, and guidance 

documents will be applied. 

(10) Any additional EM&V information needed to ensure that 

savings from EE programs and projects are credibly quantifiable 

and verifiable 

 (h) EM&V reports for demand-side EE must describe and 

document the following: 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using credible 

and appropriate industry-standard practices and guidance 

documents. 

(2) EM&V reports must document how applicable EM&V criteria 

were applied to quantify results. 

(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 
Page 1446 of 1486

project-level EM&V reports used to compile total MWh savings and 

generation. 

 (b) In each EM&V plan, the owner or operator of the 

affected EGU or qualifying ERC generating resource shall certify 

the following: 

 (1) I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, 

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 

possibility of fine or imprisonment. 

§ 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 must 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 
Page 1447 of 1486

requirements of § 60.5795. 

 (3) Verify that the activity, project, or program is in 

place and has been implemented in accordance with each specific 

element in the EM&V plan or report (e.g., that the installation 

rate is met, that the installation meets quality standards, that 

the measures are operating correctly and have the potential to 

generate anticipated savings) 

 (4) Review any documents required in the EM&V plan or 

report and any documents necessary to verify the MWh generated 

by the qualifying ERC generating resource. 

 (5) Verify any calculations, and the appropriateness of the 

calculation methodology, used to generate credits. 

 (6) For a qualifying ERC energy resource, verify the 

metered data specified in of § 60.5795. 

 (7) For a qualifying ERC energy saving activity, verify 

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 must 

compare reported electricity generation to an engineering 
Page 1448 of 1486

estimate of the maximum generation potential of the qualified 

renewable energy resource, based on, at a minimum, its maximum 

nameplate capacity in MW and the number of days since the prior 

cumulative meter reading was entered in the qualified state ERC 

tracking system. If the data entered exceeds the estimated 

technically feasible generation, the generation will be 

designated “pending” until the reported data and the estimate 

are reconciled. 

 (b) Your plan must ensure that the subject of any 

verification assurance plans, must 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 must 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, 
Page 1449 of 1486

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 

possibility of fine or imprisonment. 

§ 60.5797 What standards must the independent third party 

verifier meet? 

 (a) Your plan must ensure that any verification assurance 

plan must be drafted by a person (including any corporate parent 

or subsidiary, any contractors or subcontractors, and the actual 

person) who meets the following: 

 (1) Is a professional engineer or has other appropriate 

technical qualification; 

 (2) Is not an, and is not employed by or receiving payment 

(directly or indirectly) from any, owner or operator of an 

qualifying ERC generating resource (e.g., a renewable energy 

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 
Page 1450 of 1486

environmental attribute related to the use, generation or saving 

of electricity; 

 (6) Attests, in its verification report, to compliance with 

the American Evaluation Association requirements for 

verification; and 

 (7) Has not been debarred, suspended, or proposed for 

debarment pursuant to the Government-wide Debarment and 

Suspension regulations, 40 CFR part 32, or the Debarment, 

Suspension and Ineligibility provisions of the Federal 

Acquisition Regulations, 48 CFR part 9, subpart 9.4. 

 (b) Your plan must ensure that any qualified state ERC 

tracking system and any independent third party verifier must 

maintain, for its employees, and must ensure the maintenance of, 

for any parties that it employs, professional liability 

insurance, as defined in 31 C.F.R. 50.5(q), through an insurance 

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 

must 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
Page 1451 of 1486

§ 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 

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. 
Page 1452 of 1486

(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); 

(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; 
Page 1453 of 1486

 (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 is subject to a federally enforceable permit 

limiting, or has historically limited, its fossil fuel use to 

10% or less of its annual capacity factor; 

(5) EGUs that are a combined heat and power unit that is 

subject to a federally enforceable permit currently limiting and 

always have been 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? 
Page 1454 of 1486

(a) You must require, in your plan, affected EGUs to meet 

emission standards equal to the 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 require your affected EGUs to meet 

emission standards that differ from the CO2 emission performance 

rates listed in table 1 of this subpart, provided that you 

demonstrate that the affected EGUs in your state will 

collectively meet their CO2 emission performance rate by 

achieving statewide emission goals which are equivalent and no 

less stringent than the CO2 emission performance rates listed in 

table 1, and provided that your equivalent statewide CO2 emission 

goals take one of the following forms: 

(1) Average statewide rate-based CO2 emission goals listed 

in table 2 of this subpart, except as provided in 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). 
Page 1455 of 1486

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 

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, you may 

submit state plan revisions to make corrections to them, 

provided those revisions result in no more than a 2 percent 

change in the state goal; and 
Page 1456 of 1486

(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. 

(e) Nothing in this subpart precludes an affected EGU from 

complying with its emission standard or you from meeting your 

state measures. 

§ 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 (7) of this section. 

(1) The owner of operator of an affected EGU required to 

meet a rate based or mass based emission standard must prepare a 

monitoring plan in accordance with the applicable provisions in 

§ 75.53(g) and (h) of this chapter. 

(2) Each compliance period shall include only “valid 

operating hours” in the compliance period, i.e., operating hours 

for which: 

(i) “Valid data” (as defined in §60.5840) are obtained for 

all of the parameters used to determine the hourly CO2 mass 

emissions (lbs); and 
Page 1457 of 1486

(ii) The corresponding hourly net energy output value is 

also valid data (Note: for hours with no useful output, zero is 

considered to be a valid value). 

(3) 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)(3)(i) through (v) of this section, 

except as provided in paragraph (a)(4) of this section. 

(i) The owner or operator of an affected EGU must install, 

certify, operate, maintain, and calibrate a CO2 continuous 

emissions monitoring system (CEMS) to directly measure and 

record CO2 concentrations in the affected EGU exhaust gases 

emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to § 75.10(a)(3)(i) of this chapter. 

As an alternative to direct measurement of CO2 concentration, 

provided that the affected EGU does not use carbon separation 

(e.g., carbon capture and storage), the owner or operator or an 

affected EGU may use data from a certified oxygen (O2) monitor to 

calculate hourly average CO2 concentrations, in accordance with 

§75.10(a)(3)(iii) of this chapter. If 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. 
Page 1458 of 1486

(ii) For each continuous 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 A and B 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 EGU; the owner or 

operator of an affected EGU must not apply the bias adjustment 

factors described in section 7.6.5 of Appendix A to part 75 of 

this chapter to the exhaust gas flow rate data. 

(4) The owner or operator of an affected EGU may determine 

site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of appendix F to part 75 of this chapter, and may 

use these Fc values in the emissions calculations instead of 

using the default Fc values in the Equation G-4 nomenclature. 

(5) 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 
Page 1459 of 1486

is a combined heat and power facility must install, calibrate, 

maintain and operate equipment to continuously measure and 

record on an hourly basis useful thermal output and, if 

applicable, mechanical output, which are used with net electric 

output to determine net energy output. The owner or operator 

must calculate net energy output according to paragraph 

(a)(5)(i) of this section. 

(i) For each valid operating hour of a compliance period 

that was used in paragraph (a)(3) of this section to calculate 

the total CO2 mass emissions, you must determine Pnet (the 

corresponding hourly gross or net energy output in MWh) 

according to the procedures in paragraphs (a)(5)(i)(A) and (B) 

of this section, as appropriate for the type of affected EGU(s). 

For an operating hour in which a valid CO2 mass emissions value 

is determined according to paragraph (a)(3) of this section, if 

there is no gross or net electrical output, but there is 

mechanical or useful thermal output, you must still determine 

the net energy output for that hour. In addition, for an 

operating hour in which a valid CO2 mass emissions value is 

determined according to paragraph (a)(3) of this section, but 

there is no (i.e., zero) gross electrical, mechanical, or useful 

thermal output, you must use that hour in the compliance 

determination. For hours or partial hours where the gross 

electric output is equal to or less than the auxiliary loads, 
Page 1460 of 1486

net electric output shall be counted as zero for this 

calculation. 

(A) Calculate Pnet for your affected EGU using the following 

equation. All terms in the equation must be expressed in units 

of megawatt-hours (MWh). To convert each hourly net energy 

output value reported under part 75 of this chapter to MWh, 

multiply the MW by the corresponding EGU or stack operating time 

in hours. 

Where: a 

Pnet = Net energy output of your affected EGU for each 

valid operating hour (as defined in 

60.5820(a)(2)) in MWh. 

(Pe)ST = Electric energy output plus mechanical energy 

output (if any) of steam turbines in MWh. 

(Pe)CT = Electric energy output plus mechanical energy 

output (if any) of stationary combustion 

turbine(s) in MWh. 

(Pe)IE = Electric energy output plus mechanical energy 

output (if any) of your affected EGU’s integrated 

equipment that provides electricity or mechanical 

energy to the affected EGU or auxiliary equipment 

in MWh. 

(Pe)FW = Electric energy used to power boiler feedwater 

Deleted: ܲ௡௘௧ = ሺ௉௘ሻೄ೅ା ሺ௉௘ሻ಴೅ ା ሺ௉௘ሻ಺ಶିሺ௉௘ሻಷೈ

T ൅ ሾ ሺܲݐሻ௉ௌ ൅

ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ
Page 1461 of 1486

pumps at steam generating units in MWh. Not 

applicable to stationary combustion turbines, 

IGCC EGUs, or EGUs complying with a net energy 

output based standard. 

(Pt)PS = Useful thermal output of steam (measured relative 

to SATP conditions, as applicable) that is used 

for applications that do not generate additional 

electricity, produce mechanical energy output, or 

enhance the performance of the affected EGU. This 

is calculated using the equation specified in 

paragraph (a)(5)(i)(B) of this section in MWh. 

(Pt)HR = Non steam useful thermal output (measured 

relative to SATP conditions, as applicable) from 

heat recovery that is used for applications other 

than steam generation or performance enhancement 

of the affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to SATP 

conditions, as applicable) from any integrated 

equipment is used for applications that do not 

generate additional steam, electricity, produce 

mechanical energy output, or enhance the 

performance of the affected EGU in MWh. 

T = Electric Transmission and Distribution Factor. 

T = 0.95 for a combined heat and power affected EGU 
Page 1462 of 1486

where at least on an annual basis 20.0 percent of 

the total gross or net energy output consists of 

electric or direct mechanical output and 20.0 

percent of the total gross or net energy output 

consists of useful thermal output on a 12-

operating month rolling average basis. 

T = 1.0 for all other affected EGUs. 

(B) If applicable to your affected EGU, you must calculate 

(Pt)PS using the following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) (or pounds 

(lb)) for the operating hour. 

H = Enthalpy of the steam at measured temperature and 

pressure (relative to SATP conditions, as 

applicable) in Joules per kilogram (J/kg) (or 

Btu/lb). 

3.6 x 109 = Conversion factor (J/MWh) (or 3.413 x 106 

Btu/MWh). 

(6) In accordance with § 60.13(g), if two or more affected 

EGUs implementing the continuous emissions monitoring provisions 

in paragraph (a)(2) of this section share a common exhaust gas 

Deleted: ሺܲݐሻ௉ௌ 	ൌ	 ொ೘ ൈ ு

ଷ.଺	ൈ ଵ଴వ
Page 1463 of 1486

stack and are subject to the same emissions standard, the owner 

or operator may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

owner or operator of an affected EGU chooses this option, the 

hourly net electric output for the common stack must be the sum 

of the hourly net electric output of the individual affected 

facility and the operating time must be expressed as “stack 

operating hours” (as defined in § 72.2 of this chapter). 

(7) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU implementing the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), the hourly CO2 mass 

emissions and the “stack operating time” (as defined in § 72.2 

of this chapter) at each stack or duct must be monitored 

separately. In this case, the owner or operator of an affected 

EGU must determine compliance with an applicable emissions 

standard by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the net energy output 

for the affected EGU. 

(b) Your plan must require the owner or operator of each 

affected EGU covered by your plan to maintain the records, as 

described in (b)(1) through (2) of this subpart, for at least 5 
Page 1464 of 1486

years following the date of each compliance period, occurrence, 

measurement, maintenance, corrective action, report, or record. 

(1) The owner or operator of an affected EGU must maintain 

each record on site for at least 2 years after the date of each 

compliance period, 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 § 60.5775. 

(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 generated by the 

affected EGU or used by the affected EGU in its compliance 

demonstration 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. 
Page 1465 of 1486

(B) All independent third party verifier verification 

assurance plans. 

(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) Your plan must require the owner or operator of an 

affected EGU covered by your plan to report according to 

paragraphs (c)(1) through (3) 

(1) Owners or operators of an affected EGU must include in 

a report submitted to you at the end of 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. A plan may require affected EGUs to report all hourly 

CO2 emissions, all hourly net electric output and all hourly net 

energy output measurements to the EPA electronically pursuant to 

requirements in 40 CFR Part 75 in lieu of requiring hourly data 

to be reported to the state at the end of each compliance 

period. 

(2) For each affected EGU’s compliance period, owners and 

operators of affected EGUs must include in a report at the end 

of their affected EGU’s applicable compliance period their 

applicable emission standard. An owner or operator must also 
Page 1466 of 1486

include in the report the affected EGUs calculated emission 

performance as a CO2 emission rate or cumulative mass in units of 

the standard required in § 60.5815. 

(3) 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 

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 information relied upon 

in support of any demonstration of plan components, plan 

requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for each 

interim step and the interim period. After 2029 states must keep 

records of all information relied upon in support of any 

continued demonstration that the final emissions goals are being 

achieved. 
Page 1467 of 1486

(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. 

(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 
Page 1468 of 1486

of the period. The interim period reporting starts with a 

reporting covering interim step 1 due no later than July 1, 

2025. The final period reports start with a bi-annual report 

covering the first final step (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 

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 
Page 1469 of 1486

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 

(2) You must include information regarding the status of 

the periodic programmatic milestones to show progress in program 

implementation. The programmatic milestones with specific dates 

for achievement must be consistent with the state measures 

included in the state plan submittal. 

(d) If your plan includes the requirement for emission 

standards on your affected EGUs 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 
Page 1470 of 1486

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 

plan to be fully in place within 18 months of the due date of 

the report required in paragraph (b) of this section. In 

addition, the notification must describe the steps taken by the 

state to inform the affected EGUs in its state that the backstop 

has been triggered. 

(2) You must submit a notification in the report required 

under paragraph (b) of this section to the EPA if your affected 

EGUs, at the end of any interim step or final step, 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 steps that will be taken 

by you to implement the backstop so that it is fully in place 
Page 1471 of 1486

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 interim period used to determine 

compliance with your interim CO2 emission performance rate or 

emission goal. The calculated value must be in units consistent 

with the approach you set in your plan for the interim period. 

§ 60.5835 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, 

any plan revisions, and all state reports required to be 

submitted to the EPA by a the state plan must be reported 

through EPA’s State Plan Electronic Collection System (SPeCS). 

States who claim that a state plan submittal of supporting 

documentation includes confidential business information (CBI) 

must submit that information on a compact disc, flash drive, or 

other commonly used electronic storage media to the EPA. The 
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electronic media must be clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local 

Programs Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703. 

(c) Only a submittal by the Governor’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 

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. 
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(d) The submission of the information by the authorized 

official must be in a non-editable format. In addition to the 

non-editable version all plan components designated as federally 

enforceable must also be submitted in an editable version. 

Following initial plan approval, states must provide the EPA 

with an editable copy of any submitted revision to existing 

approved federally enforceable plan components, including state 

plan backstop measures. The editable copy of any such submitted 

plan revision must indicate the changes made at the state level, 

if any, to the existing approved federally enforceable plan 

components, using a mechanism such as redline/strikethrough. 

These changes are not part of the state plan until formal 

approval by EPA. 

(e) You must provide the EPA with a non-editable and 

editable copy of any submitted revision to existing approved 

federally enforceable plan components, including state plan 

backstop measures. The editable copy of any such submitted plan 

revision must indicate the changes made 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? 
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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. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, integrated gasification combined cycle 

(IGCC), or stationary combustion turbine that meets the relevant 

applicability conditions in section § 60.5805. 

Allowance system means a control program under which the 

owner or operator of each affected EGU is required to hold an 

authorization for each specified unit of carbon dioxide emitted 

from that facility during a specified period and which limits 

the total amount of such authorizations available to be held for 

carbon dioxide for a specified period and allows the transfer of 

such authorizations not used to meet the authorization-holding 

requirement. 

Annual capacity factor means the ratio between the actual 

heat input to an EGU during a calendar year and the potential 

heat input to the EGU had it been operated for 8,760 hours 

during a calendar year at the base load rating. 

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady state basis, as 

determined by the physical design and characteristics of the EGU 

at ISO conditions. For a stationary combustion turbine, base 

load rating includes the heat input from duct burners. 
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CO2 emission goal means a statewide rate-based CO2 emission 

goal or mass-based CO2 emission goal specified in § 60.5815. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

(not meeting the definition of natural gas), coal-oil mixtures, 

and coal-water mixtures are included in this definition for the 

purposes of this 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 
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other control areas and contributing to frequency regulation of 

the interconnection.

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, 
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or measure administered by a state, utility, or other entity 

that is currently established. This may include a regulation or 

other legal requirement that includes past, current, and future 

obligations, or current programs and measures that are in place 

and are anticipated to be continued 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. 

Final period means the period that begins on January 1, 

2030 and continues thereafter. The final period is comprised of 

final steps, each of which may be no longer then two calendar 

years (with a calendar year beginning on January 1 and ending on 

December 31).

Final step means an increment of plan performance within 

the final period, with each final step being no longer then two 

calendar years (with a calendar year beginning on January 1 and 

ending on December 31), with the first step in the final period 

beginning on January 1, 2030 and ending no later than December 

31, 2031. 

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, 
Page 1478 of 1486

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. 

The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit during operation. 

Interim period means the period of eight calendar years 

from January 1, 2022 to December 31, 2029. The interim period is 

comprised of at least three interim steps, interim step 1, 

interim step 2, and interim step 3, and may be comprised of more 

than three interim steps at your discretion, provided your first 

and second interim steps and no single interim step is longer 

than three calendar years each (with a calendar year beginning 
Page 1479 of 1486

on January 1 and ending on December 31), and your last interim 

step is no longer than two calendar years (with a calendar year 

beginning on January 1 and ending on December 31).

Interim step means an increment of plan performance within 

the interim period. You must have at least three interim steps 

within the interim period. You may have more than three interim 

steps at your discretion, provided your first and second interim 

steps and no single interim step is longer than three calendar 

years each (with a calendar year beginning on January 1 and 

ending on December 31), and your last interim step is no longer 

than two calendar years (with a calendar year beginning on 

January 1 and ending on December 31).

Interim step 1 means the period of three calendar years 

from January 1 2022 to December 31, 2024.

Interim step 2 means the period of three calendar years 

from January 1, 2025 to December 31, 2027.

Interim step 3 means the period of two calendar years from 

January 1, 2028 to December 31, 2029.

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at 

ISO conditions and includes, but is not limited to, distillate 

oil and residual oil. 

Mechanical output means the useful mechanical energy that 
Page 1480 of 1486

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 

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 
Page 1481 of 1486

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, 

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, 
Page 1482 of 1486

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, 

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 
Page 1483 of 1486

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 

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 
Page 1484 of 1486

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 

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 
Page 1485 of 1486

to SATP conditions from the measured thermal output. 

Valid data means quality-assured data generated by 

continuous monitoring systems that are installed, operated, and 

maintained according to part 75 of this chapter. For CEMS, the 

initial certification requirements in §75.20 of this chapter and 

appendix A to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart; for ongoing quality assurance, the daily, quarterly, and 

semiannual/annual test requirements in sections 2.1, 2.2, and 

2.3 of appendix B to part 75 of this chapter must be met and the 

data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter apply. For fuel flow 

meters, the initial certification requirements in section 2.1.5 

of appendix D to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart (except for 

qualifying commercial billing meters under section 2.1.4.2 of 

appendix D), and for on-going quality assurance, the provisions 

in section 2.1.6 of appendix D to part 75 of this chapter apply 

(except for qualifying commercial billing meters). 

Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates 

(Pounds of CO2 Per Net MWh) 

Affected EGU Interim Rate Final Rate Formatted Table
Page 1486 of 1486

Steam generating 

unit or integrated 

gasification 

combined cycle 

(IGCC) 

[X] 1,290 

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] 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Short Tons of CO2) 

[Placeholder for table]