Vol. 80 Friday, 

No. 205 October 23, 2015 

Book 2 of 2 Books 

Pages 64661–65120 

Part III 

Environmental Protection Agency 

40 CFR Part 60 

Carbon Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units; Final Rule 


tkelley on DSK3SPTVN1PROD with BOOK 2
64662 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2013–0602; FRL–9930–65– 

OAR] 

RIN 2060–AR33 

Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: 

Electric Utility Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: In this action, the 

Environmental Protection Agency (EPA) 

is establishing final emission guidelines 

for states to follow in developing plans 

to reduce greenhouse gas (GHG) 

emissions from existing fossil fuel-fired 

electric generating units (EGUs). 

Specifically, the EPA is establishing: 

Carbon dioxide (CO2) emission 

performance rates representing the best 

system of emission reduction (BSER) for 

two subcategories of existing fossil fuelfired EGUs—fossil fuel-fired electric 

utility steam generating units and 

stationary combustion turbines; statespecific CO2 goals reflecting the CO2

emission performance rates; and 

guidelines for the development, 

submittal and implementation of state 

plans that establish emission standards 

or other measures to implement the CO2

emission performance rates, which may 

be accomplished by meeting the state 

goals. This final rule will continue 

progress already underway in the U.S. 

to reduce CO2 emissions from the utility 

power sector. 

DATES: This final rule is effective on 

December 22, 2015. 

ADDRESSES: Docket. The EPA has 

established a docket for this action 

under Docket No. EPA–HQ–OAR–2013– 

0602. All documents in the docket are 

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

index. Although listed in the index, 

some information is not publicly 

available (e.g., confidential business 

information (CBI) or other information 

for which disclosure is restricted by 

statute). Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in http://

www.regulations.gov or in hard copy at 

the EPA Docket Center, EPA WJC West 

Building, Room 3334, 1301 Constitution 

Ave. NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding federal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. For additional 

information about the EPA’s public 

docket, visit the EPA Docket Center 

homepage at http://www2.epa.gov/

dockets. 

World Wide Web. In addition to being 

available in the docket, an electronic 

copy of this final rule will be available 

on the World Wide Web (WWW). 

Following signature, a copy of this final 

rule will be posted at the following 

address: http://www.epa.gov/

cleanpowerplan/. A number of 

documents relevant to this rulemaking, 

including technical support documents 

(TSDs), a legal memorandum, and the 

regulatory impact analysis (RIA), are 

also available at http://www.epa.gov/

cleanpowerplan/. These and other 

related documents are also available for 

inspection and copying in the EPA 

docket for this rulemaking. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Amy Vasu, Sector Policies and Programs 

Division (D205–01), U.S. EPA, Research 

Triangle Park, NC 27711; telephone 

number (919) 541–0107, facsimile 

number (919) 541–4991; email address: 

vasu.amy@epa.gov or Mr. Colin 

Boswell, Measurements Policy Group 

(D243–05), Sector Policies and Programs 

Division, U.S. EPA, Research Triangle 

Park, NC 27711; telephone number (919) 

541–2034, facsimile number (919) 541– 

4991; email address: boswell.colin@

epa.gov. 

SUPPLEMENTARY INFORMATION: 

Acronyms. A number of acronyms 

and chemical symbols are used in this 

preamble. While this may not be an 

exhaustive list, to ease the reading of 

this preamble and for reference 

purposes, the following terms and 

acronyms are defined as follows: 

ACEEE American Council for an EnergyEfficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and 

Congress of Industrial Organizations 

ASTM American Society for Testing and 

Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per 

Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or 

Sequestration) 

CEIP Clean Energy Incentive Program 

CEMS Continuous Emissions Monitoring 

System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE U.S. Department of Energy 

ECMPS Emission Collection and 

Monitoring Plan System 

EE Energy Efficiency 

EERS Energy Efficiency Resource Standard 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EM&V Evaluation, Measurement and 

Verification 

EO Executive Order 

EPA Environmental Protection Agency 

FERC Federal Energy Regulatory 

Commission 

ERC Emission Rate Credit 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined 

Cycle 

IPCC Intergovernmental Panel on Climate 

Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt 

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatthour 

LBNL Lawrence Berkeley National 

Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 

MWh Megawatt-hour 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOX Nitrogen Oxides 

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 

PUC Public Utilities Commission 

RE Renewable Energy 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission Organization 

SBA Small Business Administration 

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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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64663 

II. Background 

A. Climate Change Impacts From GHG 

Emissions 

B. GHG Emissions From Fossil Fuel-Fired 

EGUs 

C. The Utility Power Sector 

D. Challenges in Controlling Carbon 

Dioxide Emissions 

E. Clean Air Act Regulations for Power 

Plants 

F. Congressional Awareness of Climate 

Change 

G. International Agreements and Actions 

H. Legislative and Regulatory Background 

for CAA Section 111 

I. Statutory and Regulatory Requirements 

J. Clean Power Plan Proposal and 

Supplemental Proposal 

K. Stakeholder Outreach and Consultations 

L. Comments on the Proposal 

III. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

B. Summary of Legal Basis 

IV. Authority for This Rulemaking, Definition 

of Affected Sources, and Treatment of 

Categories 

A. EPA’s Authority Under CAA Section 

111(d) 

B. CAA Section 112 Exclusion to CAA 

Section 111(d) Authority 

C. Authority To Regulate EGUs 

D. Definition of Affected Sources 

E. Combined Categories and Codification 

in the Code of Federal Regulations 

V. The Best System of Emission Reduction 

and Associated Building Blocks 

A. The Best System of Emission Reduction 

(BSER) 

B. Legal Discussion of Certain Aspects of 

the BSER 

C. Building Block 1—Efficiency 

Improvements at Affected Coal-Fired 

Steam EGUs 

D. Building Block 2—Generation Shifts 

Among Affected EGUs 

E. Building Block 3—Renewable 

Generating Capacity 

VI. Subcategory-Specific CO2 Emission 

Performance Rates 

A. Overview 

B. Emission Performance Rate 

Requirements 

C. Form of the Emission Performance Rates 

D. Emission Performance Rate-Setting 

Equation and Computation Procedure 

VII. Statewide CO2 Goals 

A. Overview 

B. Reconstituting Statewide Rate-Based 

CO2 Emission Performance Goals From 

the Subcategory-Specific Emission 

Performance Rates 

C. Quantifying Mass-Based CO2 Emission 

Performance Goals From the Statewide 

Rate-Based CO2 Emission Performance 

Goals 

D. Addressing Potential Leakage in 

Determining the Equivalence of 

Statewide CO2 Emission Performance 

Goals 

E. State Plan Adjustments of State Goals 

F. Geographically Isolated States and 

Territories With Affected EGUs 

VIII. State Plans 

A. Overview 

B. Timeline for State Plan Performance and 

Provisions To Encourage Early Action 

C. State Plan Approaches 

D. State Plan Components and 

Approvability Criteria 

E. State Plan Submittal and Approval 

Process and Timing 

F. State Plan Performance Demonstrations 

G. Additional Considerations for State 

Plans 

H. Resources for States to Consider in 

Developing Plans 

I. Considerations for CO2 Emission 

Reduction Measures That Occur at 

Affected EGUs 

J. Additional Considerations and 

Requirements for Mass-Based State Plans 

K. Additional Considerations and 

Requirements for Rate-Based State Plans 

L. Treatment of Interstate Effects 

IX. Community and Environmental Justice 

Considerations 

A. Proximity Analysis 

B. Community Engagement in State Plan 

Development 

C. Providing Communities With Access to 

Additional Resources 

D. Federal Programs and Resources 

Available to Communities 

E. Multi-Pollutant Planning and CoPollutants 

F. Assessing Impacts of State Plan 

Implementation 

G. EPA Continued Engagement 

X. Interactions With Other EPA Programs and 

Rules 

A. Implications for the NSR Program 

B. Implications for the Title V Program 

C. Interactions With Other EPA Rules 

XI. Impacts of This Action 

A. What are the air impacts? 

B. Endangered Species Act 

C. What are the energy impacts? 

D. What are the compliance costs? 

E. What are the economic and employment 

impacts? 

F. What are the benefits of the proposed 

action? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

J. Executive Order 12898, Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act (CRA) 

XIII. Statutory Authority 

I. General Information 

A. Executive Summary 

1. Introduction 

This final rule is a significant step 

forward in reducing greenhouse gas 

(GHG) emissions in the U.S. In this 

action, the EPA is establishing for the 

first time GHG emission guidelines for 

existing power plants. These final 

emission guidelines, which rely in large 

part on already clearly emerging growth 

in clean energy innovation, 

development and deployment, will lead 

to significant carbon dioxide (CO2) 

emission reductions from the utility 

power sector that will help protect 

human health and the environment 

from the impacts of climate change. 

This rule establishes, at the same time, 

the foundation for longer term GHG 

emission reduction strategies necessary 

to address climate change and, in so 

doing, confirms the international 

leadership of the U.S. in the global effort 

to address climate change. In this final 

rule, we have taken care to ensure that 

achievement of the required emission 

reductions will not compromise the 

reliability of our electric system, or the 

affordability of electricity for 

consumers. This final rule is the result 

of unprecedented outreach and 

engagement with states, tribes, utilities, 

and other stakeholders, with 

stakeholders providing more than 4.3 

million comments on the proposed rule. 

In this final rule, we have addressed the 

comments and concerns of states and 

other stakeholders while staying 

consistent with the law. As a result, we 

have followed through on our 

commitment to issue a plan that is fair, 

flexible and relies on the accelerating 

transition to cleaner power generation 

that is already well underway in the 

utility power sector. 

Under the authority of Clean Air Act 

(CAA) section 111(d), the EPA is 

establishing CO2 emission guidelines for 

existing fossil fuel-fired electric 

generating units (EGUs)—the Clean 

Power Plan. These final guidelines, 

when fully implemented, will achieve 

significant reductions in CO2 emissions 

by 2030, while offering states and 

utilities substantial flexibility and 

latitude in achieving these reductions. 

In this final rule, the EPA is establishing 

a CO2 emission performance rate for 

each of two subcategories of fossil fuelfired EGUs—fossil fuel-fired electric 

steam generating units and stationary 

combustion turbines—that expresses the 

‘‘best system of emissions reduction 

. . . adequately demonstrated’’ (BSER) 


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64664 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1Under CAA section 111(d), pursuant to 40 CFR 

60.22(b)(5), states must establish, in their state 

plans, emission standards that reflect the degree of 

emission limitation achievable through the 

application of the ‘‘best system of emission 

reduction’’ that, taking into account the cost of 

achieving such reduction and any non-air quality 

health and environmental impacts and energy 

requirements, the Administrator determines has 

been adequately demonstrated (i.e., the BSER). 

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

authorized to determine the BSER and to calculate 

the amount of emission reduction achievable 

through applying the BSER. The state is authorized 

to identify the emission standard or standards that 

reflect that amount of emission reduction. 

2 In the case of a tribe that has one or more 

affected EGUs in its area of Indian country, the tribe 

has the opportunity, but not the obligation, to 

establish a CO2 emission standard for each affected 

EGU located in its area of Indian country and a 

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

country. If the tribe chooses to establish its own 

plan, it must seek and obtain authority from the 

EPA to do so pursuant to 40 CFR 49.9. If it chooses 

not to seek this authority, the EPA has the 

responsibility to determine whether it is necessary 

or appropriate, in order to protect air quality, to 

establish a CAA section 111(d) plan for an area of 

Indian country where affected EGUs are located. 

for CO2 from the power sector.1 The 

EPA is also establishing state-specific 

rate-based and mass-based goals that 

reflect the subcategory-specific CO2

emission performance rates and each 

state’s mix of affected EGUs. The 

guidelines also provide for the 

development, submittal and 

implementation of state plans that 

implement the BSER—again, expressed 

as CO2 emission performance rates— 

either directly by means of sourcespecific emission standards or other 

requirements, or through measures that 

achieve equivalent CO2 reductions from 

the same group of EGUs. 

States with one or more affected EGUs 

will be required to develop and 

implement plans that set emission 

standards for affected EGUs. The CAA 

section 111(d) emission guidelines that 

the EPA is promulgating in this action 

apply to only the 48 contiguous states 

and any Indian tribe that has been 

approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and 

implement a CAA section 111(d) plan.2

Because Vermont and the District of 

Columbia do not have affected EGUs, 

they will not be required to submit a 

state plan. Because the EPA does not 

possess all of the information or 

analytical tools needed to quantify the 

BSER for the two non-contiguous states 

with otherwise affected EGUs (Alaska 

and Hawaii) and the two U.S. territories 

with otherwise affected EGUs (Guam 

and Puerto Rico), these emission 

guidelines do not apply to those areas, 

and those areas will not be required to 

submit state plans on the schedule 

required by this final action. 

The emission standards in a state’s 

plan may incorporate the subcategoryspecific CO2 emission performance rates 

set by the EPA or, in the alternative, 

may be set at levels that ensure that the 

state’s affected EGUs, individually, in 

aggregate, or in combination with other 

measures undertaken by the state 

achieve the equivalent of the interim 

and final CO2 emission performance 

rates between 2022 and 2029 and by 

2030, respectively. State plans must 

also: (1) Ensure that the period for 

emission reductions from the affected 

EGUs begin no later than 2022, (2) show 

how goals for the interim and final 

periods will be met, (3) ensure that, 

during the period from 2022 to 2029, 

affected EGUs in the state collectively 

meet the equivalent of the interim 

subcategory-specific CO2 emission 

performance rates, and (4) provide for 

periodic state-level demonstrations 

prior to and during the 2022–2029 

period that will ensure required CO2

emission reductions are being 

accomplished and no increases in 

emissions relative to each state’s 

planned emission reduction trajectory 

are occurring. A Clean Energy Incentive 

Program (CEIP) will provide 

opportunities for investments in 

renewable energy (RE) and demand-side 

energy efficiency (EE) that deliver 

results in 2020 and/or 2021. The plans 

must be submitted to the EPA in 2016, 

though an extension to 2018 is available 

to allow for the completion of 

stakeholder and administrative 

processes. 

The EPA is promulgating: (1) 

Subcategory-specific CO2 emission 

performance rates, (2) state rate-based 

goals, and (3) state mass-based CO2

goals that represent the equivalent of 

each state’s rate-based goal. This will 

facilitate states’ choices in developing 

their plans, particularly for those 

seeking to adopt mass-based allowance 

trading programs or other statewide 

policy measures as well as, or instead 

of, source-specific requirements. The 

EPA received significant comment to 

the effect that mass-based allowance 

trading was not only highly familiar to 

states and EGUs, but that it could be 

more readily applied than rate-based 

trading for achieving emission 

reductions in ways that optimize 

affordability and electric system 

reliability. 

In this summary, we discuss the 

purpose of this rule, the major 

provisions of the final rule, the context 

for the rulemaking, key changes from 

the proposal, the estimated CO2

emission reductions, and the costs and 

benefits expected to result from full 

implementation of this final action. 

Greater detail is provided in the body of 

this preamble, the RIA, the response to 

comments (RTC) documents, and 

various TSDs and memoranda 

addressing specific topics. 

2. Purpose of This Rule 

The purpose of this rule is to protect 

human health and the environment by 

reducing CO2 emissions from fossil fuelfired power plants in the U.S. These 

plants are by far the largest domestic 

stationary source of emissions of CO2, 

the most prevalent of the group of air 

pollutant GHGs that the EPA has 

determined endangers public health and 

welfare through its contribution to 

climate change. This rule establishes for 

the first time emission guidelines for 

existing power plants. These guidelines 

will lead to significant reductions in 

CO2 emissions, result in cleaner 

generation from the existing power 

plant fleet, and support continued 

investments by the industry in cleaner 

power generation to ensure reliable, 

affordable electricity now and into the 

future. 

Concurrent with this action, the EPA 

is also issuing a final rule that 

establishes CO2 emission standards of 

performance for new, modified, and 

reconstructed power plants. Together, 

these rules will reduce CO2 emissions 

by a substantial amount while ensuring 

that the utility power sector in the U.S. 

can continue to supply reliable and 

affordable electricity to all Americans 

using a diverse fuel supply. As with 

past EPA rules addressing air pollution 

from the utility power sector, these 

guidelines have been designed with a 

clear recognition of the unique features 

of this sector. Specifically, the agency 

recognizes that utilities provide an 

essential public service and are 

regulated and managed in ways unlike 

any other industrial activity. In 

providing assurances that the emission 

reductions required by this rule can be 

achieved without compromising 

continued reliable, affordable 

electricity, this final rule fully accounts 

for the critical service utilities provide. 

As with past rules under CAA section 

111, this rule relies on proven 

technologies and measures to set 

achievable emission performance rates 

that will lead to cost-effective pollutant 

emission reductions, in this case CO2

emission reductions at power plants, 

across the country. In fact, the emission 

guidelines reflect strategies, 

technologies and approaches already in 

widespread use by power companies 

and states. The vast preponderance of 

the input we received from stakeholders 

is supportive of this conclusion. 

States will play a key role in ensuring 

that emission reductions are achieved at 

a reasonable cost. The experience of 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64665 

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

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

image/president27sclimateactionplan.pdf. 

states in this regard is especially 

important because CAA section 111(d) 

relies on the well-established state-EPA 

partnership to accomplish the required 

CO2 emission reductions. States will 

have the flexibility to choose from a 

range of plan approaches and measures, 

including numerous measures beyond 

those considered in setting the CO2

emission performance rates, and this 

final rule allows and encourages states 

to adopt the most effective set of 

solutions for their circumstances, taking 

account of cost and other 

considerations. This rulemaking, which 

will be implemented through the stateEPA partnership, is a significant step 

that will reduce air pollution, in this 

case GHG emissions, in the U.S. At the 

same time, the final rule greatly 

facilitates flexibility for EGUs by 

establishing a basis for states to set 

trading-based emission standards and 

compliance strategies. The rule 

establishes this basis by including both 

uniform emission performance rates for 

the two subcategories of sources and 

also state-specific rate- and mass-based 

goals. 

This final rule is a significant step 

forward in implementing the President’s 

Climate Action Plan.3 To address the 

far-reaching harmful consequences and 

real economic costs of climate change, 

the President’s Climate Action Plan 

details a broad array of actions to reduce 

GHG emissions that contribute to 

climate change and its harmful impacts 

on public health and the environment. 

Climate change is already occurring in 

this country, affecting the health, 

economic well-being and quality of life 

of Americans across the country, and 

especially those in the most vulnerable 

communities. This CAA section 111(d) 

rulemaking to reduce GHG emissions 

from existing power plants, and the 

concurrent CAA section 111(b) 

rulemaking to reduce GHG emissions 

from new, modified, and reconstructed 

power plants, implement one of the 

strategies of the Climate Action Plan. 

Nationwide, by 2030, this final CAA 

section 111(d) existing source rule will 

achieve CO2 emission reductions from 

the utility power sector of 

approximately 32 percent from CO2

emission levels in 2005. 

The EPA projects that these 

reductions, along with reductions in 

other air pollutants resulting directly 

from this rule, will result in net climate 

and health benefits of $25 billion to $45 

billion in 2030. At the same time, coal 

and natural gas will remain the two 

leading sources of electricity generation 

in the U.S., with coal providing about 

27 percent of the projected generation 

and natural gas providing about 33 

percent of the projected generation. 

3. Summary of Major Provisions 

a. Overview. The fundamental goal of 

this rule is to reduce harmful emissions 

of CO2 from fossil fuel-fired EGUs in 

accordance with the requirements of the 

CAA. The June 2014 proposal for this 

rule was designed to meet this 

overarching goal while accommodating 

two important objectives. The first was 

to establish guidelines that reflect both 

the unique interconnected and 

interdependent manner in which the 

power system operates and the actions, 

strategies, and policies states and 

utilities have already been undertaking 

that are resulting in CO2 emission 

reductions. The second objective was to 

provide states and utilities with broad 

flexibility and choice in meeting those 

requirements in order to minimize costs 

to ratepayers and to ensure the 

reliability of electricity supply. In this 

final rule, the EPA has focused on 

changes that, in addition to being 

responsive to the critical concerns and 

priorities of stakeholders, more fully 

accomplish these objectives. 

While our consideration of public 

input and additional information has 

led to notable revisions from the 

emission guidelines we proposed in 

June 2014, the proposed guidelines 

remain the foundation of this final rule. 

These final guidelines build on the 

progress already underway to reduce the 

carbon intensity of power generation in 

the U.S., especially through the lowest 

carbon-intensive technologies, while 

reflecting the unique interconnected 

and interdependent system within 

which EGUs operate. Thus, the BSER, as 

determined in these guidelines, 

incorporates a range of CO2-reducing 

actions, while at the same time adhering 

to the fundamental approach the EPA 

has relied on for decades in 

implementing section 111 of the CAA. 

Specifically, in making its BSER 

determination, the EPA examined not 

only actions, technologies and measures 

already in use by EGUs and states, but 

also deliberately incorporated in its 

identification of the BSER the unique 

way in which affected EGUs actually 

operate in providing electricity services. 

This latter feature of the BSER mirrors 

Congress’ approach to regulating air 

pollution in this sector, as exemplified 

by Title IV of the CAA. There, Congress 

established a pollution reduction 

program specifically for fossil fuel-fired 

EGUs and designed the sulfur dioxide 

(SO2) portion of that program with 

express recognition of the utility power 

sector’s ability to shift generation among 

various EGUs, which enabled pollution 

reduction by increasing reliance on RE 

and even on demand-side EE. The result 

of our following Congress’ recognition 

of the interdependent operation of EGUs 

within an interconnected grid is the 

incorporation in the BSER of measures, 

such as shifting generation to loweremitting NGCC units and increased use 

of RE, that rely on the current 

interdependent operation of EGUs. As 

we noted in the proposal and note here 

as well, the EPA undertook an 

unprecedented and sustained process of 

engagement with the public and 

stakeholders. It is, in many ways, as a 

direct result of public discussion and 

input that the EPA came to recognize 

the substantial extent to which the 

BSER needed to account for the unique 

interconnected and interdependent 

operations of EGUs if it was to meet the 

criteria on which the EPA has long 

relied in making BSER determinations. 

Equally important, these guidelines 

offer states and owners and operators of 

EGUs broad flexibility and latitude in 

complying with their obligations. 

Because affordability and electricity 

system reliability are of paramount 

importance, the rule provides states and 

utilities with time for planning and 

investment, which is instrumental to 

ensuring both manageable costs and 

system reliability, as well as to 

facilitating clean energy innovation. The 

final rule continues to express the CO2

emission reduction requirements in 

terms of state goals, as well as in terms 

of emission performance rates for the 

two subcategories of affected EGUs, 

reflecting the particular mix of power 

generation in each state, and it 

continues to provide until 2030, fifteen 

years from the date of this final rule, for 

states and sources to achieve the CO2

reductions. Numerous commenters, 

including most sources, states and 

energy agencies, indicated that this was 

a reasonable timeframe. The final 

guidelines also continue to provide an 

option where programs beyond those 

directly limiting power plant emission 

rates can be used for compliance (i.e., 

policies, programs and other measures). 

The final rule also continues to allow, 

but not require, multi-state approaches. 

Finally, EPA took care to ensure that 

states could craft their own emissions 

reduction trajectories in meeting the 

interim goals included in this final rule. 

b. Opportunities for states. As stated 

above, the final guidelines are designed 

to build on and reinforce progress by 

states, cities and towns, and companies 

on a growing variety of sustainable 

strategies to reduce power sector CO2


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64666 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

4The EPA’s proposed CAA section 111(d) federal 

plan and model rules for existing fossil fuel-fired 

EGUs are being published concurrently with this 

final rule. 

emissions. States, in their CAA section 

111(d) plans, will be able to rely on, and 

extend, programs they may already have 

created to address emissions of air 

pollutants, and in particular CO2, from 

the utility power sector or to address the 

sector from an overall perspective. 

Those states committed to Integrated 

Resource Planning (IRP) will be able to 

establish their CO2 reduction plans 

within that framework, while states 

with a more deregulated power sector 

system will be able to develop CO2

reduction plans within that specific 

framework. Each state will have the 

opportunity to take advantage of a wide 

variety of strategies for reducing CO2

emissions from affected EGUs, 

including demand-side EE programs 

and mass-based trading, which some 

suggested in their comments. The EPA 

and other federal entities, including the 

U.S. Department of Energy (DOE), the 

Federal Energy Regulatory Commission 

(FERC) and the U.S. Department of 

Agriculture (USDA), among others, are 

committed to sharing expertise with 

interested states as they develop and 

implement their plans. 

States will be able to address the 

economic interests of their utilities and 

ratepayers by using the flexibilities in 

this final action to reduce costs to 

consumers, minimize stranded assets, 

and spur private investments in RE and 

EE technologies and businesses. They 

may also, if they choose, work with 

other states on multi-state approaches 

that reflect the regional structure of 

electricity operating systems that exists 

in most parts of the country and is 

critical to ensuring a reliable supply of 

affordable energy. The final rule gives 

states the flexibility to implement a 

broad range of approaches that 

recognize that the utility power sector is 

made up of a diverse range of 

companies of various sizes that own and 

operate fossil fuel-fired EGUs, including 

vertically integrated companies in 

regulated markets, independent power 

producers, rural cooperatives and 

municipally-owned utilities, some of 

which are likely to have more direct 

access than others to certain types of 

GHG emission reduction opportunities, 

but all of which have a wide range of 

opportunities to achieve reductions or 

acquire clean generation. 

Again, with features that facilitate 

mass-based and/or interstate trading, the 

final guidelines also empower affected 

EGUs to pursue a broad range of choices 

for compliance and for integrating 

compliance action with the full range of 

their investments and operations. 

c. Main elements. This final rule 

comprises three main elements: (1) Two 

subcategory-specific CO2 emission 

performance rates resulting from 

application of the BSER to the two 

subcategories of affected EGUs; (2) statespecific CO2 goals, expressed as both 

emission rates and as mass, that reflect 

the subcategory-specific CO2 emission 

performance rates and each state’s mix 

of affected EGUs the two performance 

rates; and (3) guidelines for the 

development, submittal and 

implementation of state plans that 

implement those BSER emission 

performance rates either through 

emission standards for affected EGUs, or 

through measures that achieve the 

equivalent, in aggregate, of those rates as 

defined and expressed in the form of the 

state goals. 

In this final action, the EPA is setting 

emission performance rates, phased in 

over the period from 2022 through 2030, 

for two subcategories of affected fossil 

fuel-fired EGUs—fossil fuel-fired 

electric utility steam-generating units 

and stationary combustion turbines. 

These rates, applied to each state’s 

particular mix of fossil fuel-fired EGUs, 

generate the state’s carbon intensity goal 

for 2030 (and interim rates for the 

period 2022–2029). Each state will 

determine whether to apply these to 

each affected EGU or to take an 

alternative approach and meet either an 

equivalent statewide rate-based goal or 

statewide mass-based goal. The EPA 

does not prescribe how a state must 

meet the emission guidelines, but, if a 

state chooses to take the path of meeting 

a state goal, these final guidelines 

identify the methods that a state can or, 

in some cases, must use to demonstrate 

that the combination of measures and 

standards that the state adopts meets its 

state-level CO2 goals. While the EPA 

accomplishes the phase-in of the 

interim goal by way of annual emission 

performance rates, states and EGUs may 

meet their respective emission 

reduction obligations ‘‘on average’’ over 

that period following whatever emission 

reduction trajectory they determine to 

pursue over that period. 

CAA section 111(d) creates a 

partnership between the EPA and the 

states under which the EPA establishes 

emission guidelines and the states take 

the lead on implementing them by 

establishing emission standards or 

creating plans that are consistent with 

the EPA emission guidelines. The EPA 

recognizes that each state has differing 

policy considerations—including 

varying regional emission reduction 

opportunities and existing state 

programs and measures—and that the 

characteristics of the electricity system 

in each state (e.g., utility regulatory 

structure and generation mix) also 

differ. Therefore, as in the proposal, 

each state will have the latitude to 

design a program to meet sourcecategory 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 massbased program that the EPA is 

proposing concurrently with this 

action.4

To facilitate the state planning 

process, this final rule establishes 

guidelines for the development, 

submittal, and implementation of state 

plans. The final rule describes the 

components of a state plan, the 

additional latitude states have in 

developing strategies to meet the 

emission guidelines, and the options 

they have in the timing of submittal of 

their plans. This final rule also gives 

states considerable flexibility with 

respect to the timeframes for plan 

development and implementation, as 

well as the choice of emission reduction 

measures. The final rule provides up to 

fifteen years for full implementation of 

all emission reduction measures, with 

incremental steps for planning and then 

for demonstration of CO2 reductions 

that will ensure that progress is being 

made in achieving CO2 emission 

reductions. States will be able to choose 

from a wide range of emission reduction 

measures, including measures that are 

not part of the BSER, as discussed in 

detail in section VIII.G of this preamble. 

d. Determining the BSER. In issuing 

this final rulemaking, the EPA is 

implementing statutory provisions that 

have been in place since Congress first 

enacted the CAA in 1970 and that have 

been implemented pursuant to 

regulations promulgated in 1975 and 

followed in numerous subsequent CAA 

section 111 rulemakings. These 

requirements call on the EPA to develop 

emission guidelines that reflect the 

EPA’s determination of the ‘‘best system 

of emission reduction . . . adequately 

demonstrated’’ for states to follow in 


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5The final emission guidelines for landfill gas 

emissions from municipal solid waste landfills, 

published on March 12, 1996, and amended on June 

16, 1998 (61 FR 9905 and 63 FR 32743, 

respectively), provide an example, as the guidelines 

allow either of two approaches for controlling 

landfill gas—by recovering the gas as a fuel, for sale, 

and removing from the premises, or by destroying 

the organic content of the gas on the premises using 

a control device. Recovering the gas as a fuel source 

was a practice already being used by some affected 

sources prior to promulgation of the rulemaking. 

6The EPA notes that, in quantifying the emission 

reductions that are achievable through application 

of the BSER, some building blocks will apply to 

some, but not all, affected EGUs. Specifically, 

building block 1 will apply to affected coal-fired 

steam EGUs, building block 2 will apply to all 

affected steam EGUs (both coal-fired and oil/gasfired), and building block 3 will apply to all 

affected EGUs. 

7The CAA section 111(d) emission guidelines 

apply to the 50 states, the District of Columbia, U.S. 

territories, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as 

eligible to develop and implement a CAA section 

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

these governments are not specifically listed, the 

term ‘‘state’’ is used to represent them. Because 

Vermont and the District of Columbia do not have 

affected EGUs, they will not be required to submit 

a state plan. Because the EPA does not possess all 

of the information or analytical tools needed to 

quantify the BSER for the two non-contiguous states 

with affected EGUs (Alaska and Hawaii) and the 

two U.S. territories with affected EGUs (Guam and 

Puerto Rico), we are not finalizing emission 

performance rates in those areas at this time, and 

those areas will not be required to submit state 

plans until we do. 

formulating plans to establish emission 

standards to implement the BSER. 

As the EPA has done in making BSER 

determinations in previous CAA section 

111 rulemakings, for this final BSER 

determination, the agency considered 

the types of strategies that states and 

owners and operators of EGUs are 

already employing to reduce the 

covered pollutant (in this case, CO2) 

from affected sources (in this case, fossil 

fuel-fired EGUs).5

In so doing, as has always been the 

case, our considerations were not 

limited solely to specific technologies or 

equipment in hypothetical operation; 

rather, our analysis encompassed the 

full range of operational practices, 

limitations, constraints and 

opportunities that bear upon EGUs’ 

emission performance, and which 

reflect the unique interconnected and 

interdependent operations of EGUs and 

the overall electricity grid. 

In this final action, the agency has 

determined that the BSER comprises the 

first three of the four proposed 

‘‘building blocks,’’ with certain 

refinements to the three building blocks. 

The three building blocks are: 

1. Improving heat rate at affected coal-fired 

steam EGUs. 

2. Substituting increased generation from 

lower-emitting existing natural gas combined 

cycle units for generation from higheremitting affected steam generating units. 

3. Substituting increased generation from 

new zero-emitting renewable energy 

generating capacity for generation from 

affected fossil fuel-fired generating units. 

These three building blocks are 

approaches that are available to all 

affected EGUs, either through direct 

investment or operational shifts or 

through emissions trading where states, 

which must establish emission 

standards for affected EGUs, do so by 

incorporating emissions trading.6 At the 

same time, and as we noted in the 

proposal, there are numerous other 

measures available to reduce CO2

emissions from affected EGUs, and our 

determination of the BSER does not 

necessitate the use of the three building 

blocks to their maximum extent, or even 

at all. The building blocks and the BSER 

determination are described in detail in 

section V of this preamble. 

e. CO2 state-level goals and 

subcategory-specific emission 

performance rates. 

(1) Final CO2 goals and emission 

performance rates. 

In this action, the EPA is establishing 

CO2 emission performance rates for two 

subcategories of affected EGUs—fossil 

fuel-fired electric utility steam 

generating units and stationary 

combustion turbines. For fossil fuelfired steam generating units, we are 

finalizing an emission performance rate 

of 1,305 lb CO2/MWh. For stationary 

combustion turbines, we are finalizing 

an emission performance rate of 771 lb 

CO2/MWh. As we did at proposal, for 

each state, we are also promulgating 

rate-based CO2 goals that are the 

weighted aggregate of the emission 

performance rates for the state’s EGUs. 

To ensure that states and sources can 

choose additional alternatives in 

meeting their obligations, the EPA is 

also promulgating each state’s goal 

expressed as a CO2 mass goal. The 

inclusion of mass-based goals, along 

with information provided in the 

proposed federal plan and model rules 

that are being issued concurrently with 

this rule, paves the way for states to 

implement mass-based trading, as some 

states have requested, reflecting their 

view that mass-based trading provides 

significant advantages over rate-based 

trading. 

Affected EGUs, individually, in 

aggregate, or in combination with other 

measures undertaken by the state, must 

achieve the equivalent of the CO2

emission performance rates, expressed 

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

(2) Interim CO2 emission performance 

rates and state-specific goals. 

The best system of emission reduction 

includes both the measures for reducing 

CO2 emissions and the timeframe over 

which they can be implemented. In this 

final action, the EPA is establishing an 

8-year interim period, beginning in 2022 

instead of 2020, over which to achieve 

the full required reductions to meet the 

CO2 performance rates, a 

commencement date more than six 

years from October 23, 2015, the date of 

this rulemaking. This 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. The interim 

steps are presented both in terms of 

emission performance rates for the two 

subcategories of affected EGUs and in 

terms of state goals, expressed both as 

a rate and as a mass. A state may adopt 

emission standards for its sources that 

are identical to these interim emission 

performance rates or, alternatively, 

adapt these steps to accommodate the 

timing of expected reductions, as long 

as the state’s interim goal is met over the 

8-year period. 

f. State plans.7

In this action, the EPA is establishing 

final guidelines for states to follow in 

developing, submitting and 

implementing their plans. In developing 

plans, states will need to choose the 

type of plan they will develop. They 

will also need to include required plan 

components in their plan submittals, 

meet plan submittal deadlines, achieve 

the required CO2 emission reductions 

over time, and provide for monitoring 

and periodic reporting of progress. As 

with the BSER determination, 

stakeholder comments have provided 

both data and recommendations to 

which these final guidelines are 

responsive. 

(1) Plan approaches. 

To comply with these emission 

guidelines, a state will have to ensure, 

through its plan, that the emission 

standards it establishes for its sources 

individually, in aggregate, or in 

combination with other measures 

undertaken by the state, represent the 

equivalent of the subcategory-specific 

CO2 emission performance rates. This 

final rule includes several options for 

state plans, as discussed in the proposal 

and in many of the comments we 

received. 

First, in the final rule, states may 

establish emission standards for their 

affected EGUs that mirror the uniform 

emission performance rates for the two 

subcategories of sources included in this 

final rule. They may also pursue 

alternative approaches that adopt 

emission standards that meet the 


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8The CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule, available 

in the docket for this rulemaking. 

9The EPA would take action on such a state plan 

through independent notice and comment 

rulemaking. 

10 40 CFR 60.23. 

11A 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. 

uniform emission performance rates, or 

emission standards that meet either the 

rate-based goal promulgated for the state 

or the alternative mass-based goal 

promulgated for the state. It is for the 

purpose of providing states with these 

choices that the EPA is providing statespecific rate-based and mass-based goals 

equivalent to the emission performance 

rates that the EPA is establishing for the 

two subcategories of fossil fuel-fired 

EGUs. A detailed explanation of rateand mass-based goals is provided in 

section VII of this preamble and in a 

TSD.8 In developing its plan, each state 

and eligible tribe electing to submit a 

plan will need to choose whether its 

plan will result in the achievement of 

the CO2 emission performance rates, 

statewide rate-based goals, or statewide 

mass-based goals by the affected EGUs. 

The second major set of options 

provided in the final rule includes the 

types of measures states may rely on 

through the state plans. A state will be 

able to choose to establish emission 

standards for its affected EGUs 

sufficient to meet the requisite 

performance rates or state goal, thus 

placing all of the requirements directly 

on its affected EGUs, which we refer to 

as the ‘‘emission standards approach.’’ 

Alternatively, a state can adopt a ‘‘state 

measures approach,’’ which would 

result in the affected EGUs meeting the 

statewide mass-based goal by allowing a 

state to rely upon state-enforceable 

measures on entities other than affected 

EGUs, in conjunction with any federally 

enforceable emission standards the state 

chooses to impose on affected EGUs. 

With a state measures approach, the 

plan must also include a contingent 

backstop of federally enforceable 

emission standards for affected EGUs 

that fully meet the emission guidelines 

and that would be triggered if the plan 

failed to achieve the required emission 

reductions on schedule. A state would 

have the option of basing its backstop 

emission standards on the model rule, 

which focuses on the use of emissions 

trading as the core mechanism and 

which the EPA is proposing today. A 

state that adopts a state measures 

approach must use its mass CO2

emission goal as the metric for 

demonstrating plan performance. 

The final rule requires that the state 

plan submittal include a timeline with 

all of the programmatic plan 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 plan milestone steps that 

the state indicated it would take during 

the period from the submittal of the 

final plan through the end of 2020, and 

that the state is on track to implement 

the approved state plan as of January 1, 

2022. 

The plan must also include a process 

for reporting on plan implementation, 

progress toward achieving CO2 emission 

reductions, and implementation of 

corrective actions, in the event that the 

state fails to achieve required emission 

levels in a timely fashion. Beginning 

January 1, 2025, and then January 1, 

2028, January 1, 2030, and then every 

two calendar years thereafter, the state 

will be required to compare emission 

levels achieved by affected EGUs in the 

state with the emission levels projected 

in the state plan and report the results 

of that comparison to the EPA by July 

1 of those calendar years. 

Existing state programs can be aligned 

with the various state plan options 

further described in Section VIII. A state 

plan that uses one of the finalized 

model rules, which the EPA is 

proposing concurrently with this action, 

could be presumptively approvable if 

the state plan meets all applicable 

requirements.9 The plan guidelines 

provide the states with the ability to 

achieve the full reductions over a multiyear 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).10 In the proposal, 

the EPA identified certain additional 

elements that should be contained in 

state plans. In this final action, in 

response to comments, the EPA is 

making several revisions to the 

components required in a state plan 

submittal and is also incorporating the 

approvability criteria into the final list 

of components required in a state plan 

submittal. In addition, we have 

organized the state plan components to 

reflect: (1) Components required for all 

state plan submittals; (2) additional 

components required for the emission 

standards approach; and (3) additional 

components required for the state 

measures approach. 

All state plans must include the 

following components: 

• Description of the plan 

• Applicability of state plans to affected 

EGUs 

• Demonstration that the plan submittal is 

projected to achieve the state’s CO2 emission 

performance rates or state CO2 goal 11

• Monitoring, reporting and recordkeeping 

requirements for affected EGUs 

• State recordkeeping and reporting 

requirements 

• Public participation and certification of 

hearing on state plan 

• Supporting documentation 

Also, in submitting state plans, states 

must provide documentation 

demonstrating that they have 

considered electric system reliability in 

developing their plans. 

Further, in this final rule, the EPA is 

requiring states to demonstrate how 

they are meaningfully engaging all 

stakeholders, including workers and 

low-income communities, communities 

of color, and indigenous populations 

living near power plants and otherwise 

potentially affected by the state’s plan. 

In their plan submittals, states must 

describe their engagement with their 

stakeholders, including their most 

vulnerable communities. The 

participation of these communities, 

along with that of ratepayers and the 

public, can be expected to help states 

ensure that state plans maintain the 

affordability of electricity for all and 

preserve and expand jobs and job 

opportunities as they move forward to 

develop and implement their plans. 

State plan submittals using the 

emission standards approach must also 

include: 

• Identification of each affected EGU; 

identification of 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 


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federally enforceable emission standards; and 

monitoring, recordkeeping and reporting 

requirements. 

• Identification of each state measure and 

demonstration that each state measure will 

result in reductions that are quantifiable, 

non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, 

each state plan must follow the EPA 

implementing regulations at 40 CFR 

60.23. 

(3) Timing and process for state plan 

submittal and review. 

Because of the compelling need for 

actions to begin the steps necessary to 

reduce GHG emissions from EGUs, the 

EPA proposed that states submit their 

plans within 13 months of the date of 

this final rule and that reductions begin 

in 2020. In light of the comments 

received and in order to provide 

maximum flexibility to states while still 

taking timely action to reduce CO2

emissions, in this final rule the EPA is 

allowing for a 2-year extension until 

September 6, 2018, for both individual 

and multi-state plans, to provide a total 

of 3 years for states to submit a final 

plan if an extension is received. 

Specifically, the final rule requires each 

state to submit a final plan by 

September 6, 2016. Since some states 

may need more than one year to 

complete all of the actions needed for 

their final state plans, including 

technical work, state legislative and 

rulemaking activities, a robust public 

participation process, coordination with 

third parties, coordination among states 

involved in multi-state plans, and 

consultation with reliability entities, the 

EPA is allowing an optional two-phased 

submittal process for state plans. If a 

state needs additional time to submit a 

final plan, then the state may request an 

extension by submitting an initial 

submittal by September 6, 2016. For the 

extension to be granted, the initial 

submittal must address three required 

components sufficiently to demonstrate 

that a state is able to undertake steps 

and processes necessary to timely 

submit a final plan by the extended date 

of September 6, 2018. These 

components are: An identification of 

final plan approach or approaches 

under consideration, including a 

description of progress made to date; an 

appropriate explanation for why the 

state needs additional time to submit a 

final plan beyond September 6, 2016; 

and a demonstration of how they have 

been engaging with the public, 

including vulnerable communities, and 

a description of how they intend to 

meaningfully engage with community 

stakeholders during the additional time 

(if an extension is granted) for 

development of the final plan, as 

described in section VIII.E of this 

preamble. As further described in 

section VIII.B of this preamble, the EPA 

is establishing a CEIP in order to 

promote early action. States’ 

participation in the CEIP is optional. In 

order for a state to participate in the 

program, it must include in its initial 

submittal, if applicable, a non-binding 

statement of intent to participate in the 

CEIP; if a state is submitting a final plan 

by September 6, 2016, it must include 

such a statement of intent as part of its 

supporting documentation for the plan. 

If the initial submittal includes those 

components and if the EPA does not 

notify the state that the initial submittal 

does not contain the required 

components, then, within 90 days of the 

submittal, the extension of time to 

submit a final plan will be deemed 

granted. A state will then have until no 

later than September 6, 2018, to submit 

a final plan. The EPA will also be 

working with states during the period 

after they make their initial submittals 

and provide states with any necessary 

information and assistance during the 

90-day period. Further, states 

participating in a multi-state plan may 

submit a single joint plan on behalf of 

all of the participating states. 

States and tribes that do not have any 

affected EGUs in their jurisdictional 

boundaries may provide emission rate 

credits (ERCs) to adjust CO2 emissions, 

provided they are connected to the 

contiguous U.S. grid and meet other 

requirements for eligibility. There are 

certain limitations and restrictions for 

generating ERCs, and these, as well as 

associated requirements, are explained 

in section VIII of this preamble. 

Following submission of final plans, 

the EPA will review plan submittals for 

approvability. Given a similar timeline 

accorded under section 110 of the CAA, 

and the diverse approaches states may 

take to meet the CO2 emission 

performance rates or equivalent 

statewide goals in the emission 

guidelines, the EPA is extending the 

period for EPA review and approval or 

disapproval of plans from the fourmonth period provided in the EPA 

implementing regulations to a twelvemonth period. This timeline will 

provide adequate time for the EPA to 

review plans and follow notice-andcomment rulemaking procedures to 

ensure an opportunity for public 

comment. The EPA, especially through 

our regional offices, will be available to 

work with states as they develop their 

plans, in order to make review of 

submitted plans more straightforward 

and to minimize the chances of 

unexpected issues that could slow down 

approval of state plans. 

(4) Timing for implementing the CO2

emission guidelines. 

The EPA recognizes that the measures 

states and utilities have been and will 

be taking to reduce CO2 emissions from 

existing EGUs can take time to 

implement. We also recognize that 

investments in low-carbon intensity and 

RE and in EE strategies are currently 

underway and in various stages of 

planning and implementation widely 

across the country. We carefully 

reviewed information submitted to us 

regarding the feasible timing of various 

measures and identifying concerns that 

the required CO2 emission reductions 

could not be achieved as early as 2020 

without compromising electric system 

reliability, imposing unnecessary costs 

on ratepayers, and requiring 

investments in more carbon-intensive 

generation, while diverting investment 

in cleaner technologies. The record is 

compelling. To respond to these 

concerns and to reflect the period of 

time required for state plan 

development and submittal by states, 

review and approval by the EPA, and 

implementation of approved plans by 

states and affected EGUs, the EPA is 

determining in this final rule that 

affected EGUs will be required to begin 

to make reductions by 2022, instead of 

2020, as proposed, and meet the final 

CO2 emission performance rates or 

equivalent statewide goals by no later 

than 2030. The EPA is establishing an 

8-year interim period that begins in 

2022 and goes through 2029, and which 

is separated into three steps, 2022–2024, 

2025–2027, and 2028–2029, each 

associated with its own interim goal. 

Affected EGUs must meet each of the 

interim period step 1, 2, and 3 CO2

emission performance rates, or, 

following the emissions reduction 

trajectory designed by the state itself, 

must meet the equivalent statewide 

interim period goals, on average, that a 

state may establish over the 8-year 

period from 2022–2029. The CAA 

section 111(d) plan must include those 

specific requirements. Affected EGUs 

must also achieve the final CO2

performance rates or the equivalent 

statewide goal by 2030 and maintain 

that level subsequently. This approach 

reflects adjustments to the timeframe 

over which reductions must be achieved 

that mirror the determination of the 

final BSER, which incorporates the 

phasing in of the BSER measures in 

keeping with the achievability of those 

measures. The agency believes that this 

approach to timing is reasonable and 

appropriate, is consistent with many of 

the comments we received, and will 


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best support the optimization of overall 

CO2 reductions, ratepayer affordability 

and electricity system reliability. 

The EPA recognizes that successfully 

achieving reductions by 2022 will be 

facilitated by actions and investments 

that yield CO2 emission reductions prior 

to 2022. The final guidelines include 

provisions to encourage early actions. 

States will be able to take advantage of 

the impacts of early investments that 

occur prior to the beginning of a plan 

performance period. Under a massbased plan, those impacts will be 

reflected in reductions in the reported 

CO2 emissions of affected EGUs during 

the plan performance period. Under a 

rate-based plan, states may recognize 

early actions implemented after 2012 by 

crediting MWh of electricity generation 

and savings that are achieved by those 

measures during the interim and final 

plan performance periods. This 

provision is discussed in section VIII.K 

of the preamble. 

In addition, to encourage early 

investments in RE and demand-side EE, 

the EPA is establishing the CEIP. 

Through this program, detailed in 

section VIII.B of this preamble, states 

will have the opportunity to award 

allowances and ERCs to qualified 

providers that make early investments 

in RE, as well as in demand-side EE 

programs implemented in low-income 

communities. Those states that take 

advantage of this option will be eligible 

to receive from the EPA matching 

allowances or ERCs, up to a total for all 

states that represents the equivalent of 

300 million short tons of CO2 emissions. 

The EPA will address design and 

implementation details of the CEIP in a 

subsequent action. Prior to doing so, the 

EPA will engage with states, utilities 

and other stakeholders to gather 

information regarding their interests and 

priorities with regard to implementation 

of the CEIP. 

The CEIP can play an important role 

in supporting one of the critical policy 

benefits of this rule. The incentives and 

market signal generated by the CEIP can 

help sustain the momentum toward 

greater RE investment in the period 

between now and 2022 so as to offset 

any dampening effects that might be 

created by setting the period for 

mandatory reductions to begin in 2022, 

two years later than at proposal. 

(5) Community and environmental 

justice considerations. 

Climate change is an environmental 

justice issue. Low-income communities 

and communities of color already 

overburdened by pollution are 

disproportionately affected by climate 

change and are less resilient than others 

to adapt to or recover from climatechange impacts. While this rule will 

provide broad benefits to communities 

across the nation by reducing GHG 

emissions, it will be particularly 

beneficial to populations that are 

disproportionately vulnerable to the 

impacts of climate change and air 

pollution. 

Conventional pollutants emitted by 

power plants, such as particulate matter 

(PM), SO2, hazardous air pollutants 

(HAP), and nitrogen oxides (NOx), will 

also be reduced as the plants reduce 

their carbon emissions. These pollutants 

can have significant adverse local and 

regional health impacts. The EPA 

analyzed the communities in closest 

proximity to power plants and found 

that they include a higher percentage of 

communities of color and low-income 

communities than national averages. We 

thus expect an important co-benefit of 

this rule to be a reduction in the adverse 

health impacts of air pollution on these 

low-income communities and 

communities of color. We refer to these 

communities generally as ‘‘vulnerable’’ 

or ‘‘overburdened,’’ to denote those 

communities least resilient to the 

impacts of climate change and central to 

environmental justice considerations. 

While pollution will be cut from 

power plants overall, there may be some 

relatively small number of coal-fired 

plants whose operation and 

corresponding emissions increase as 

energy providers balance energy 

production across their fleets to comply 

with state plans. In addition, a number 

of the highest-efficiency natural gasfired units are also expected to increase 

operations, but they have 

correspondingly low carbon emissions 

and are also characterized by low 

emissions of the conventional pollutants 

that contribute to adverse health effects 

in nearby communities and regionally. 

The EPA strongly encourages states to 

evaluate the effects of their plans on 

vulnerable communities and to take the 

steps necessary to ensure that all 

communities benefit from the 

implementation of this rule. In order to 

identify whether state plans are causing 

any adverse impacts on overburdened 

communities, mindful that substantial 

overall reductions, nevertheless, may be 

accompanied by potential localized 

increases, the EPA intends to perform 

an assessment of the implementation of 

this rule to determine whether it and 

other air quality rules are leading to 

improved air quality in all areas or 

whether there are localized impacts that 

need to be addressed. 

Effective engagement between states 

and affected communities is critical to 

the development of state plans. The EPA 

encourages states to identify 

communities that may be currently 

experiencing adverse, disproportionate 

impacts of climate change and air 

pollution, how state plan designs may 

affect them, and how to most effectively 

reach out to them. This final rule 

requires that states include in their 

initial submittals a description of how 

they engaged with vulnerable 

communities as they developed their 

initial submittals, as well as the means 

by which they intend to involve 

communities and other stakeholders as 

they develop their final plans. The EPA 

will provide training and other 

resources for states and communities to 

facilitate meaningful engagement. 

In addition to the benefits for 

vulnerable communities from reducing 

climate change impacts and effects of 

conventional pollutant emissions, this 

rule will also help communities by 

moving the utility industry toward 

cleaner generation and greater EE. The 

federal government is committed to 

ensuring that all communities share in 

these benefits. 

The EPA also encourages states to 

consider how they may incorporate 

approaches already used by other states 

to help low-income communities share 

in the investments in infrastructure, job 

creation, and other benefits that RE and 

demand-side EE programs provide, have 

access to financial assistance programs, 

and minimize any adverse impacts that 

their plans could have on communities. 

To help support states in taking 

concrete actions that provide economic 

development, job and electricity billcutting benefits to low-income 

communities directly, the EPA has 

designed the CEIP specifically to target 

the incentives it creates on investments 

that benefit low-income communities. 

Community and environmental 

justice considerations are discussed 

further in section IX of this preamble. 

(6) Addressing employment concerns. 

In addition, the EPA encourages states 

in designing their state plans to consider 

the effects of their plans on employment 

and overall economic development to 

assure that the opportunities for 

economic growth and jobs that the plans 

offer are realized. To the extent possible, 

states should try to assure that 

communities that can be expected to 

experience job losses can also take 

advantage of the opportunities for job 

growth or otherwise transition to 

healthy, sustainable economic growth. 

The President has proposed the 

POWER+ Plan to help communities 

impacted by power sector transition. 

The POWER+ plan invests in workers 

and jobs, addresses important legacy 

costs in coal country, and drives 


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12https://www.whitehouse.gov/the-press-office/

2015/03/27/fact-sheet-partnerships-opportunityand-workforce-and-economic-revitaliz. 

13http://www.eda.gov/power/. 14 www.epa.gov/cleanpowerplantoolbox. 

development of coal technology.12

Implementation of one key part of the 

POWER+ Plan, the Partnerships for 

Opportunity and Workforce and 

Economic Revitalization (POWER) 

initiative, has already begun. The 

POWER initiative specifically targets 

economic and workforce development 

assistance to communities affected by 

ongoing changes in the coal industry 

and the utility power sector.13

(7) Electric system reliability. 

In no small part thanks to the 

comments we received and our 

extensive consultation with key 

agencies responsible for reliability, 

including FERC and DOE, among others, 

along with EPA’s longstanding 

principles in setting emission standards 

for the utility power sector, these 

guidelines reflect the paramount 

importance of ensuring electric system 

reliability. The input we received on 

this issue focused heavily on the extent 

of the reductions required at the 

beginning of the interim period, 

proposed as 2020. We are addressing 

these concerns in large part by moving 

the beginning of the period for 

mandatory reductions under the 

program from 2020 to 2022 and 

significantly adjusting the interim goals 

so that they provide a less abrupt initial 

reduction expectation. This, in turn, 

will provide states and utilities with a 

great deal more latitude in determining 

their emission reduction trajectories 

over the interim period. As a result, 

there will be more time for planning, 

consultation and decision making in the 

formulation of state plans and in EGUs’ 

choice of compliance strategies, all 

within the existing extensive structure 

of energy planning at the state and 

regional levels. These adjustments in 

the interim goals are supported by the 

information in the record concerning 

the time needed to develop and 

implement reductions under the BSER. 

In addition, the various forms of 

flexibility retained and enhanced in this 

final rule, including opportunities for 

trading within and between states, and 

other multi-state compliance 

approaches, will further support electric 

system reliability. 

The final guidelines address electric 

system reliability in several additional 

important ways. Numerous commenters 

urged us to include, as part of the plan 

development or approval process, input 

from review by energy regulatory 

agencies and reliability entities. In the 

final rule, we are requiring that each 

state demonstrate in its final state plan 

submittal that it has considered 

reliability issues in developing its plan. 

Second, we recognize that issues may 

arise during the implementation of the 

guidelines that may warrant 

adjustments to a state’s plan in order to 

maintain electric system reliability. The 

final guidelines make clear that states 

have the ability to propose amendments 

to approved plans in the event that 

unanticipated and significant electric 

system reliability challenges arise and 

compel affected EGUs to generate at 

levels that conflict with their 

compliance obligations under those 

plans. 

As a final element of reliability 

assurance, the rule also provides for a 

reliability safety valve for individual 

sources where there is a conflict 

between the requirements the state plan 

imposes on a specific affected EGU and 

the maintenance of electric system 

reliability in the face of an extraordinary 

and unanticipated event that presents 

substantial reliability concerns. 

We anticipate that these situations 

will be extremely rare because the states 

have the flexibility to craft requirements 

for their EGUs that will provide long 

averaging periods and/or compliance 

mechanisms, such as trading, whose 

inherent flexibility will make it unlikely 

that an individual unit will find itself in 

this kind of situation. As one example, 

under compliance regimes that allow 

individual EGUs to establish 

compliance through the acquisition and 

holding of allowances or ERCs equal to 

their emissions, an EGU’s need to 

continue to operate—and emit—for the 

purposes of ensuring system reliability 

will not put the EGU into noncompliance, provided, of course, it 

obtains the needed allowances or credits 

in a timely fashion. We, nevertheless, 

agree with many commenters that it is 

prudent to provide an electric system 

reliability safety valve as a precaution. 

Finally, the EPA, DOE and FERC have 

agreed to coordinate their efforts, at the 

federal level, to help ensure continued 

reliable electricity generation and 

transmission during the implementation 

of the final rule. The three agencies have 

set out a memorandum that reflects their 

joint understanding of how they will 

work together to monitor 

implementation, share information, and 

to resolve any difficulties that may be 

encountered. 

As a result of the many features of this 

final rule that provide states and 

affected EGUs with meaningful time and 

decision making latitude, we believe 

that the comprehensive safeguards 

already in place in the U.S. to ensure 

electric system reliability will continue 

to operate effectively as affected EGUs 

reduce their CO2 emissions under this 

program. 

(8) Outreach and resources for 

stakeholders. 

To provide states, U.S. territories, 

tribes, utilities, communities, and other 

interested stakeholders with 

understanding about the rule 

requirements, and to provide 

efficiencies where possible and reduce 

the cost and administrative burden, the 

EPA will continue to work with states, 

tribes, territories, and stakeholders to 

provide information and address 

questions about the final rule. Outreach 

will include opportunities for states and 

tribes to participate in briefings, 

teleconferences, and meetings about the 

final rule. The EPA’s ten regional offices 

will continue to be the entry point for 

states, tribes and territories to ask 

technical and policy questions. The 

agency will host (or partner with 

appropriate groups to co-host) a number 

of webinars about various components 

of the final rule; these webinars are 

planned for the first two months after 

the final rule is issued. The EPA will 

also offer consultations with tribal 

governments. The EPA will continue 

outreach throughout the plan 

development and submittal process. The 

EPA will use information from this 

outreach process to inform the training 

and other tools that will be of most use 

to the state, tribes, and territories that 

are implementing the final rule. 

The EPA has worked with 

communities, states, tribes and relevant 

associations to develop an extensive 

training plan that will continue in the 

months after the Clean Power Plan is 

finalized. The EPA has assembled 

resources from a variety of sources to 

create a comprehensive training 

curriculum for those implementing this 

rule. Recorded presentations from the 

EPA, DOE and other federal entities will 

be available for communities, states, and 

others involved in composing and 

participating in the development of state 

plans. This curriculum is available 

online at EPA’s Air Pollution Training 

Institute. 

The EPA also expects to issue 

guidance on specific topics. As 

guidance documents, tools, templates 

and other resources become available, 

the EPA, in consultation with DOE and 

other federal agencies, will continue to 

make these resources available via a 

dedicated Web site.14

We intend to continue to work 

actively with states and tribes, as 

appropriate, to provide information and 

technical support that will be helpful to 


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64672 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

them in developing and implementing 

their plans. The EPA will engage in 

formal consultations with tribal 

governments and provide training 

tailored to the needs of tribes and tribal 

governments. 

Additional detail on aspects of the 

final rule is included in several 

technical support documents (TSDs) 

and memoranda that are available in the 

rulemaking docket. 

4. Key Changes From Proposal 

a. Overview and highlights. As noted 

earlier in this overview, the June 2014 

proposal for the rule was designed to 

meet the fundamental goal of reducing 

harmful emissions of CO2 from fossil 

fuel-fired EGUs in a manner consistent 

with the CAA requirements, while 

accommodating two important 

objectives. The first objective was to 

establish guidelines that reflect both the 

manner in which the power system 

operates and the actions and measures 

already underway across states and the 

utility power sector that are resulting in 

CO2 emission reductions. The second 

objective was to provide states and 

utilities maximum flexibility, control 

and choice in meeting their compliance 

obligations. In this final rule, the EPA 

has focused on changes that, in addition 

to being responsive to the critical 

concerns and priorities of stakeholders, 

more fully accomplish these two crucial 

objectives. 

To achieve these objectives, the June 

2014 proposal featured several 

important elements: The building block 

approach for the BSER; state-specific, 

rather than source-specific, goals; a 10- 

year interim goal that could be met ‘‘on 

average’’ over the 10-year period 

between 2020 and 2029; and a 

‘‘portfolio’’ option for state plans. These 

features were intended either to capture, 

in the emission guidelines, emission 

reduction measures already in 

widespread use or to maximize the 

range of choices that states and utilities 

could select in order to achieve their 

emission limitations at low cost while 

ensuring electric system reliability. In 

this final rule, we are retaining the key 

design elements of the proposal and 

making certain adjustments to respond 

to a variety of very constructive 

comments on ways that will implement 

the CAA section 111(d) requirements 

efficiently and effectively. 

The building block approach is a key 

feature of the proposal that we are 

retaining in the final rule, but have 

refined to include only the first three 

building blocks and to reflect 

implementation of the measures 

encompassed in the building blocks on 

a broad regional grid-level. In the 

proposal, we expressed the emission 

limitation requirements reflecting the 

BSER in terms of the state goals in order 

to provide states with maximum 

flexibility and latitude. We viewed this 

as an important feature because each 

state has its own energy profile and 

state-specific policies and needs relative 

to the production and use of electricity. 

In the final rule, we extend that 

flexibility significantly in direct 

response to comments from states and 

utilities. The final rule establishes 

source-level emission performance rates 

for the source subcategories, while 

retaining state-level rate- and massbased goals. One of the key messages 

conveyed by state and utility 

commenters was that the final rule 

should make it easier for states to adopt 

mass-based programs and for utilities 

accustomed to operating across broad 

multi-state grids to be able to avail 

themselves of more ‘‘ready-made’’ 

emissions trading regimes. The 

inclusion of both of these new 

features—mass-based state goals in 

addition to rate-based goals, and sourcelevel emission performance rates for the 

two subcategories of sources—is 

intended to make it easier for states and 

utilities to achieve these outcomes. In 

fact, these additions, together with the 

model rules and federal plan being 

proposed concurrently with this rule, 

should demonstrate the relative ease 

with which states can adopt mass-based 

trading programs, including interstate 

mass-based programs that lend 

themselves to the kind of interstate 

compliance strategies so well suited for 

integration with the current interstate 

operations of the overall utility grid. 

Many stakeholders conveyed to the 

EPA that the proposal’s interim goals for 

the 2020–2029 period were designed in 

a way that defeated the EPA’s objective 

of allowing states and utilities to shape 

their emission reduction trajectories. 

They pointed out that, in many cases, 

the timing and stringency of the states’ 

interim goals could require actions that 

could result in high costs, threaten 

electric system reliability or hinder the 

deployment of renewable technology. In 

response, the EPA has revised the 

interim goals in two critical ways. First, 

the period for mandatory reductions 

begin in 2022 rather than 2020; second, 

in keeping with the BSER, emission 

reduction requirements are phased in 

more gradually over the interim period. 

These changes will allow states and 

utilities to delineate their own emission 

reduction trajectories so as to minimize 

costs and foster broader deployment of 

RE technologies. The value of these 

changes is demonstrated by our analysis 

of the final rule, which shows lower 

program costs, especially in the early 

years of the interim period, and greater 

RE deployment, relative to the analysis 

of the proposed rule. At the same time, 

this re-design of the interim goals, 

together with refinements we have made 

to state plan requirements and the 

inclusion of a reliability safety valve, 

provide states, utilities and other 

entities with the ability to continue to 

guarantee system reliability. 

b. Outreach, engagement and 

comment record. This final rule is the 

product of one of the most extensive 

and long-running public engagement 

processes the EPA has ever conducted, 

starting in the summer of 2013, prior to 

proposal, and continuing through 

December 2014, when the public 

comment period ended, and continuing 

beyond that with consultations and 

meetings with stakeholders. The result 

of this extensive consultation was 

millions of comments from 

stakeholders, which we have carefully 

considered over the past several 

months. The EPA gained crucial 

insights from the more than 4 million 

comments that the agency received on 

the proposal and associated documents 

leading to this final rulemaking. 

Comments were provided by 

stakeholders that include state 

environmental and energy officials, 

tribal officials, public utility 

commissioners, system operators, 

owners and operators of every type of 

power generating facility, other industry 

representatives, labor leaders, public 

health leaders, public interest 

advocates, community and faith leaders, 

and members of the public. 

The insights gained from public 

comments contributed to the 

development of final emission 

guidelines that build on the proposal 

and the alternatives on which we sought 

comment. The modifications 

incorporated in the final guidelines are 

directly responsive to the comments we 

received from the many and diverse 

stakeholders. The improved guidelines 

reflect information and ideas that states 

and utilities provided to us about both 

the best approach to establishing CO2

emission reduction requirements for 

EGUs and the most effective ways to 

create true flexibility for states and 

utilities in meeting these requirements. 

These final rules also reflect the results 

of EPA’s robust consultation with 

federal, state and regional energy 

agencies and authorities, to ensure that 

the actions sources will take to reduce 

GHG emissions will not compromise 

electric system reliability or 

affordability of the U.S. electricity 

supply. Input and assistance from FERC 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64673 

and DOE have been particularly 

important in shaping some provisions in 

these final guidelines. At the same time, 

input from faith-based, communitybased and environmental justice 

organizations, who provided thoughtful 

comments about the potential impacts 

of this rule on pollution levels in 

overburdened communities and 

economic impacts, including utility 

rates in low-income communities, is 

also reflected in this rule. The final rule 

also reflects our response to concerns 

raised by labor leaders regarding the 

potential effects on workers and 

communities of the transition away 

from higher-emitting power generation 

to lower- and zero-emitting power 

generation. 

c. Key changes. The most significant 

changes in these final guidelines are: (1) 

The period for mandatory emission 

reductions beginning in 2022 instead of 

2020 and a gradual application of the 

BSER over the 2022–2029 interim 

period, such that a state has substantial 

latitude in selecting its own emission 

reduction trajectory or ‘‘glide path’’ over 

that period, (2) a revised BSER 

determination that focuses on narrower 

generation options that do not include 

demand-side EE measures and that 

includes refinements to the building 

blocks, more complete incorporation in 

the BSER of the realities of electricity 

operations over the three regional 

interconnections, and up-to-date 

information about the cost and 

availability of clean generation options, 

(3) establishment of source-specific CO2

emission performance rates that are 

uniform across the two fossil fuel-fired 

subcategories covered in these 

guidelines, as well as rate- and massbased state goals, to facilitate emission 

trading, including interstate trading and, 

in particular, mass-based trading, (4) a 

variation on the proposal’s ‘‘portfolio’’ 

option for state plans—called here the 

‘‘state measures’’ approach—that 

continues to provide states flexibility 

while ensuring that all state plans have 

federally enforceable measures as a 

backstop, (5) additional, more flexible 

options for states and utilities to adopt 

multi-state compliance strategies, (6) an 

extension of up to two years available to 

all states for submittal of their final 

compliance plans following making 

initial submittals in 2016, (7) provisions 

to encourage actions that achieve early 

reductions, including a Clean Energy 

Incentive Program (CEIP), (8) a 

combination of provisions expressly 

designed to ensure electric system 

reliability, (9) the addition of 

employment considerations for states in 

plan development, and (10) the 

expansion of considerations and 

programs for low-income and 

vulnerable communities. 

We provide summary explanations in 

the following paragraphs and more 

detailed explanations of all of these 

changes in later sections of this 

preamble and associated documents. 

(1) Mandatory reduction period 

beginning in 2022 and a gradual glide 

path. 

The proposal’s mandatory emission 

reduction period beginning in 2020 and 

the trajectory of emission reduction 

requirements in the interim period were 

both the subjects of significant 

comment. Earlier this year, FERC 

conducted a series of technical 

conferences comprising one national 

session and three regional sessions. The 

information provided by workshop 

participants echoed much of the 

material that had been submitted to the 

comment record for this rulemaking. On 

May 15, 2015, the FERC Commissioners, 

drawing upon information highlighted 

at the technical conferences, transmitted 

to the EPA some suggestions for the 

final rule. In addition, via comments, 

states, utilities, and reliability entities 

asked us to ensure adequate time for 

them to implement strategies to achieve 

CO2 reductions. They expressed concern 

that, in the proposal, at least some states 

would be required to reduce emissions 

in 2020 to levels that would require 

abrupt shifts in generation in ways that 

raised concerns about impacts to 

electric system reliability and ratepayer 

bills, as well as about stranded assets. 

To many commenters, the proposal’s 

requirement for CO2 emission 

reductions beginning in 2020, together 

with the stringency of the interim CO2

goal, posed significant reliability 

implications, in particular. In this final 

rule, the agency is addressing these 

concerns, in part, by adjusting the 

compliance timeframe from a 10-year 

interim period that begins in 2020 to an 

8-year interim period that begins in 

2022, and by refining the approach for 

meeting interim CO2 emission 

performance rates to be a gradual glide 

path separated into three steps, 2022– 

2024, 2025–2027, and 2028–2029, that 

is also achievable ‘‘on average’’ over the 

8-year interim period. In response to the 

concerns of commenters that the 

proposal’s 10-year interim target failed 

to afford sufficient flexibility, the final 

guidelines’ approach will provide states 

with realistic options for customizing 

their emission reduction trajectories. Of 

equal importance, the approach 

provides more time for planning, 

consultation and decision making in the 

formulation of state plans and in EGUs’ 

choices of compliance strategies. Both 

FERC’s May 15, 2015 letter and the 

comment record, as well as other 

information sources, made it clear that 

providing sufficient time for planning 

and implementation was essential to 

ensuring electric system reliability. 

The final guidelines’ approach to the 

interim emission performance rates is 

the result of the application of the 

measures constituting the BSER in a 

more gradual way, reflecting 

stakeholder comments and information 

about the appropriate period of time 

over which those measures can be 

deployed consistent with the BSER 

factors of cost and feasibility. In 

addition to facilitating reliable system 

operations, these changes provide states 

and utilities with the latitude to 

consider a broader range of options to 

achieve the required reductions while 

addressing concerns about ratepayer 

impacts and stranded assets. 

(2) Revised BSER determination. 

Commenters urged the EPA to confine 

its BSER determination to actions that 

involve what they characterized as more 

‘‘traditional’’ generation. While some 

stakeholders recognized demand-side 

EE as being an integral part of the 

electricity system, with many of the 

characteristics of more traditional 

generating resources, other stakeholders 

did not. As explained in section 

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

interpretation and implementation of 

CAA section 111 has allowed regulated 

entities to produce as much of a 

particular good as they desire, provided 

that they do so through an appropriately 

clean (or low-emitting) process. While 

building blocks 1, 2, and 3 fall squarely 

within this paradigm, the proposed 

building block 4 does not. In view of 

this, since the BSER must serve as the 

foundation of the emission guidelines, 

the EPA has not included demand-side 

EE as part of the final BSER 

determination. Thus, neither the final 

guidelines’ BSER determination nor the 

emission performance rates for the two 

subcategories of affected EGUs take into 

account demand-side EE. However, 

many commenters also urged the EPA to 

allow states and sources to rely on 

demand-side EE as an element of their 

compliance strategies, as demand-side 

EE is treated as functionally 

interchangeable with other forms of 

generation for planning and operational 

purposes, as EE measures are in 

widespread use across the country and 

provide energy savings that reduce 

emissions, lower electric bills, and lead 

to 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 


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meeting emission reduction 

requirements. 

In response to stakeholder comments 

on the first three building blocks and 

considerable data in the record, the EPA 

has made refinements to the building 

blocks, and these are reflected in the 

final BSER. Refinements include 

adoption of a modified approach to 

quantification of the RE component, 

exclusion of the proposed nuclear 

generation components, and adoption of 

a consistent regionalized approach to 

quantification of all three building 

blocks. The agency also recognizes the 

important functional relationship 

between the period of time over which 

measures are deployed and the 

stringency of emission limitations those 

measures can achieve practically and at 

reasonable cost. Therefore, the final 

BSER also reflects adjustments to the 

stringency of the building blocks, after 

consideration of more and less stringent 

levels, and refinements to the timeframe 

over which reductions must be 

achieved. Sections V.C through V.E of 

this preamble provide further 

information on the refinements made to 

the building blocks and the rationale for 

doing so. 

Commenters pointed out—and 

practical experience confirms—what is 

widely known: That the utility power 

sector operates over regional 

interconnections that are not 

constrained by state borders. Across a 

variety of issues raised in the proposal, 

many commenters urged that the EPA 

take that reality into account in 

developing this final rule. 

Consequently, the BSER determination 

itself (as well as a number of new 

compliance features included in this 

final rule) and the resulting subcategoryspecific emission performance rates take 

into account the grid-level operations of 

the source category. 

The final guidelines’ BSER 

determination also takes into account 

recent reductions in the cost of clean 

energy technology, as well as 

projections of continuing cost 

reductions, and continuing increases in 

RE deployment. We also updated the 

underlying analysis with the most 

recent Energy Information 

Administration (EIA) projections that 

show lower growth in electricity 

demand between 2020 and 2030 than 

previously projected. In keeping with 

these recent EIA projections, we expect 

the final guidelines will be more 

conducive to compliance, consistent 

with a strategy that allows for the 

cleanest power generation and greater 

CO2 reductions in 2030 than the 

proposal. With a date of 2022, instead 

of 2020, as proposed, for the mandatory 

CO2 emission reduction period to begin, 

the final guidelines reflect that the 

additional time aligns with the adoption 

of lower-cost clean technology and, 

thus, its incorporation in the BSER at 

higher levels. At the same time, the 

2022–2029 interim period will more 

easily allow for companies to take 

advantage of improved clean energy 

technologies as potential least cost 

options. 

(3) Uniform emission performance 

rates. 

Some stakeholders commented that 

the proposal’s approach of expressing 

the BSER in terms of state-specific goals 

deviated from the requirements of CAA 

section 111 and from previous new 

source performance standards (NSPS). 

The effect, they stated, was that the 

proposal created de facto emission 

standards for all affected EGUs but that 

these de facto standards varied widely 

depending on the state in which a given 

EGU happened to be located. Instead, 

these and other commenters stated, 

section 111 requires that EPA establish 

the BSER specifically for affected 

sources, rather than by means of merely 

setting state-specific goals, and that 

these standards be uniform. Still other 

commenters observed that the effect of 

the approach taken in the proposal of 

applying the BSER to each state’s fleet 

was to put a greater burden of 

reductions on lower-emitting or less 

carbon-intensive states and a lesser 

emission reduction burden on sources 

and states that were higher-emitting or 

more carbon-intensive. This, they 

argued, was both inequitable and at 

odds with the way in which NSPS have 

been applied in the past, where the 

higher-emitting sources have made the 

greater and more cost-effective 

reductions, while lower-emitting 

sources, whose reduction opportunities 

tend to be less cost-effective, have been 

required to make fewer reductions to 

meet the applicable standard. 

At the same time, state and utility 

commenters expressed concern that 

relying on state-specific goals and stateby-state planning could introduce 

complexity into the otherwise seamless 

integrated operation of affected EGUs 

across the multi-state grids on which 

system operators, states and utilities 

currently rely and intend to continue to 

rely. Accordingly, they recommended 

that the final guidelines facilitate 

emissions trading, in particular 

interstate trading, which would enable 

EGU operators to integrate compliance 

with CO2 emissions limitations with 

facility and grid-level operations. These 

sets of comments intersected at the 

point at which they focused on the fact 

that it is at the source level at which the 

standard is set for NSPS and at the 

source level at which compliance must 

be achieved. 

The EPA carefully considered these 

comments and while we believe that the 

approach we took at proposal was wellfounded and reflected a number of 

important considerations, we have 

concluded that there is a way to address 

these concerns while expanding upon 

the advantages offered by the proposal. 

Accordingly, the final guidelines 

establish uniform rates for the two 

subcategories of sources—an approach 

that is valuable for creating greater 

equity between and among utilities and 

states with widely varying emission 

levels and for expanding the flexibility 

of the program, especially in ways that 

have been identified as important to 

utilities and states. Specifically, the 

final guidelines express the BSER by 

means of performance-based CO2

emission rates that are uniform across 

each of two subcategories—fossil fuelfired electric steam generating units and 

stationary combustion turbines—for the 

affected EGUs covered by the 

guidelines. The rates are determined, in 

part, by applying the methodology 

identified in the Notice of Data 

Availability (NODA) published on 

October 30, 2014, which was based on 

the proposal’s building block approach. 

The final guidelines also maintain the 

approach adopted in the proposal of 

establishing state-level goals; in the final 

rule, those goals are equal to the 

weighted aggregate of the two emission 

performance rates as applied to the 

EGUs in each state. 

This approach rectifies what would 

have been an inefficient, unintended 

outcome of putting the greater reduction 

burden on lower-emitting sources and 

states while exempting higher-emitting 

sources and states. Expressing the BSER 

by means of these rates also augments 

the range of options for both states and 

EGUs for securing needed flexibility. 

Inclusion of state goals creates latitude 

for states as to how they will meet the 

guidelines. States also may meet the 

guideline requirements by adopting the 

CO2 emission performance rates as 

emission standards that apply to the 

affected EGUs in their jurisdiction. Such 

an approach would lend itself to the 

ready establishment of intra-state and 

interstate trading, with the uniform ratebased standards of performance 

established for each EGU as the basis for 

such trading. At the same time, as at 

proposal, each state also has the option 

of complying with these guidelines by 

adopting a plan that takes a different 

approach to setting standards of 

performance for its EGUs and/or by 

applying complementary or alternative 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64675 

measures to meet the state goal set by 

these guidelines—as either a rate or a 

mass total. 

During the outreach process and 

through comments, a number of state 

officials and other stakeholders 

expressed concern that the EPA’s 

approach at proposal necessitated or 

represented a significant intrusion into 

state-level energy policy-making, 

drawing the EPA well beyond the 

bounds of its CAA authority and 

expertise. In fact, these final guidelines 

are entirely respectful of the EPA’s 

responsibility and authority to regulate 

sources of air pollution. Instead, by 

establishing and operating through 

uniform performance rates for the two 

subcategories of sources that can be 

applied by states at the individual 

source level and that can readily be 

implemented through emission 

standards that incorporate emissions 

trading, these final guidelines align with 

the approach Congress and the EPA 

have consistently taken to regulating 

emissions from this and other industrial 

sectors, namely setting source-level, 

source category-wide standards that 

individual sources can meet through a 

variety of technologies and measures. 

We emphasize, at the same time, that 

while the final guidelines express the 

BSER by means of source-level CO2

emission performance rates, as well as 

state-level goals, as at proposal, each 

state will have a goal reflecting its 

particular mix of sources, and the final 

guidelines retain the flexibility inherent 

in the proposal’s state-specific goals 

approach (and, as discussed in section 

VIII of this preamble, enhanced in 

various ways). Thus, in keeping with 

the proposal’s flexibility, states may 

choose to adopt either the emission 

performance rates as emission standards 

for their sources, set different but, in the 

aggregate, equivalent rates, or fulfill 

their obligations by meeting their 

respective individual state goals. 

(4) State plan approaches. 

Commenters expressed support for 

the objectives served by the ‘‘portfolio’’ 

option in the state plan approaches 

included at proposal, but many raised 

concerns about its legality, with respect, 

in particular, to the CAA’s 

enforceability requirements. Some of 

these commenters identified a ‘‘state 

commitment approach’’ with backstop 

measures as a variation of the 

‘‘portfolio’’ approach that would retain 

the benefits of the ‘‘portfolio’’ approach 

while resolving legal and enforceability 

concerns. In this final rule, in response 

to stakeholder comments on the 

portfolio approach and alternative 

approaches, the EPA is finalizing two 

approaches: A source-based ‘‘emission 

standards’’ approach, and a ‘‘state 

measures’’ approach. Through the latter, 

states may adopt a set of policies and 

programs, which would not be federally 

enforceable, except that any standards 

imposed on affected EGUs would be 

federally enforceable. In addition, states 

would be required to include federally 

enforceable backstop measures 

applicable to each affected EGU in the 

event that the measures included in the 

state plan failed to achieve the state 

plan’s emissions reduction trajectory. 

Under these guidelines, states can 

implement the BSER through standards 

of performance incorporating the 

uniform performance rates or alternative 

but in the aggregate equivalent rates, or 

they can adopt plans that achieve in 

aggregate the equivalent of the 

subcategory-specific CO2 emission 

performance rates by relying on other 

measures undertaken by the state that 

complement source-specific 

requirements or, save for the contingent 

backstop requirement, supplant them 

entirely. This revision provides 

consistency in the treatment of sources 

while still providing maximum 

flexibility for states to design their plans 

around reduction approaches that best 

suit their policy objectives. 

(5) Emission trading programs. 

Many state and utility commenters 

supported the use of mass-based and 

rate-based emission trading programs in 

state plans, including interstate 

emission trading programs, and either 

pointed out obstacles to establishing 

such programs or suggested approaches 

that would enhance states’ and utilities’ 

ability to create and participate in such 

programs. 

Through a combination of features 

retained from the proposal and changes 

made to the proposal, these final 

guidelines provide states and utilities 

with a panoply of tools that greatly 

facilitate their putting in place and 

participating in emissions trading 

programs. These include: (1) Expressing 

BSER in uniform emission performance 

rates that states may rely on in setting 

emission standards for affected EGUs 

such that EGUs operating under such 

standards readily qualify to trade with 

affected EGUs in states that adopt the 

same approach, (2) promulgating state 

mass goals so that states can move 

quickly to establish mass-based 

programs such that their affected EGUs 

readily qualify to trade with affected 

EGUs in states that adopt the same 

approach, and (3) providing EPA 

resources and capacity to create a 

tracking system to support state 

emissions trading programs. 

(6) Extension of plan submittal date. 

Stakeholders, particularly states, 

provided compelling information 

establishing that it could take longer 

than the agency initially anticipated for 

the states to develop and submit their 

required plans. While the approach at 

proposal reflected the EPA’s conclusion 

that it was essential to the 

environmental and economic purposes 

of this rulemaking that utilities and 

states establish the path towards 

emissions reductions as early as 

possible, we recognize commenters’ 

concerns. To strike the proper balance, 

the EPA has developed a revised state 

plan submittal schedule. For states that 

cannot submit a final plan by September 

6, 2016, the EPA is requiring those 

states to make an initial submittal by 

that date to assure that states begin to 

address the urgent needs for reductions 

quickly, and is providing until 

September 6, 2018, for states to submit 

a final plan, if an extension until that 

date is justified, to address the concern 

that a submitting state needs more time 

to develop comprehensive plans that 

reflect the full range of the state’s and 

its stakeholders’ interests. 

(7) Provisions to encourage early 

action. 

Many commenters supported 

providing incentives for states and 

utilities to deploy CO2-reducing 

investments, such as RE and demandside EE measures, as early as possible. 

We also received comments from 

stakeholders regarding the 

disproportionate burdens that some 

communities already bear, and stating 

that all communities should have equal 

access to the benefits of clean and 

affordable energy. The EPA recognizes 

the validity and importance of these 

perspectives, and as a result has 

determined to provide a program— 

called the CEIP—in which states may 

choose to participate. 

The CEIP is designed to incentivize 

investment in certain RE and demandside EE projects that commence 

construction, in the case of RE, or 

commence construction, in the case of 

demand-side EE, following the 

submission of a final state plan to the 

EPA, or after September 6, 2018, for 

states that choose not to submit a final 

state plan by that date, and that generate 

MWh (RE) or reduce end-use energy 

demand (EE) during 2020 and/or 2021. 

State participation in the program is 

optional. 

Under the CEIP, a state may set aside 

allowances from the CO2 emission 

budget it establishes for the interim plan 

performance period or may generate 

early action ERCs (ERCs are discussed 

in more detail in section VIII.K.2), and 

allocate these allowances or ERCs to 


tkelley on DSK3SPTVN1PROD with BOOK 2
64676 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

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

16https://www.whitehouse.gov/the-press-office/

2015/03/27/fact-sheet-partnerships-opportunityand-workforce-and-economic-revitaliz. 

eligible projects for the MWh those 

projects generate or the end-use energy 

savings they achieve in 2020 and/or 

2021. For each early action allowance or 

ERC a state allocates to such projects, 

the EPA will provide the state with an 

appropriate number of matching 

allowances or ERCs for the state to 

allocate to the project. The EPA will 

match state-issued early action ERCs 

and allowances up to an amount that 

represents the equivalent of 300 million 

short tons of CO2 emissions. 

For a state to be eligible for a 

matching award of allowances or ERCs 

from the EPA, it must demonstrate that 

it will award allowances or ERCs only 

to ‘‘eligible’’ projects. These are projects 

that: 

• Are located in or benefit a state that 

has submitted a final state plan that 

includes requirements establishing its 

participation in the CEIP; 

• Are implemented following the 

submission of a final state plan to the 

EPA, or after September 6, 2018, for a 

state that chooses not to submit a 

complete state plan by that date; 

• For RE: Generate metered MWh 

from any type of wind or solar 

resources; 

• For EE: Result in quantified and 

verified electricity savings (MWh) 

through demand-side EE implemented 

in low-income communities; and 

• Generate or save MWh in 2020 and/ 

or 2021. 

The following provisions outline how 

a state may award early action ERCs and 

allowances to eligible projects, and how 

the EPA will provide matching ERCs or 

allowances to states. 

• For RE projects that generate 

metered MWh from any type of wind or 

solar resources: For every two MWh 

generated, the project will receive one 

early action ERC (or the equivalent 

number of allowances) from the state, 

and the EPA will provide one matching 

ERC (or the equivalent number of 

allowances) to the state to award to the 

project. 

• For EE projects implemented in 

low-income communities: For every two 

MWh in end-use demand savings 

achieved, the project will receive two 

early action ERCs (or the equivalent 

number of allowances) from the state, 

and the EPA will provide two matching 

ERCs (or the equivalent number of 

allowances) to the state to award to the 

project. 

Early action allowances or ERCs 

awarded by the state, and matching 

allowances or ERCs awarded by the EPA 

pursuant to the CEIP, may be used for 

compliance by an affected EGU with its 

emission standards and are fully 

transferrable prior to such use. 

The EPA discusses the CEIP in the 

proposed federal plan rule and will 

address design and implementation 

details of the CEIP in a subsequent 

action. Prior to doing so, the EPA will 

engage with states, utilities and other 

stakeholders to gather information 

regarding their interests and priorities 

with regard to implementation of the 

CEIP. 

(8) Provisions for electric system 

reliability. 

A number of commenters stressed the 

importance of final guidelines that 

addressed the need to ensure that EGUs 

could meet their emission reduction 

requirements without being compelled 

to take actions that would undermine 

electric system reliability. As noted 

above, the EPA has consulted 

extensively with federal, regional and 

state energy agencies, utilities and many 

others about reliability concerns and 

ways to address them. The final 

guidelines support electric system 

reliability in a number of ways, some 

inherent in the improvements made in 

the program’s design and some through 

specific provisions we have included in 

the final rule. Most important are the 

two key changes we made to the interim 

goal: Establishing 2022, instead of 2020, 

as the period for mandatory emission 

reductions begin and phasing in, over 

the 8-year period, emission performance 

rates such that the level of stringency of 

the emission performance rates in 2022– 

2024 is significantly less than that for 

the years 2028 and 2029. Since states 

and utilities need only to meet their 

interim goal ‘‘on average’’ over the 8- 

year period, these changes provide them 

with a great deal of latitude in 

determining for themselves their 

emission reduction trajectory—and they 

have additional time to do so. As a 

result, the final guidelines provide the 

ingredients that commenters, reliability 

entities and expert agencies told the 

EPA were essential to ensuring electric 

system reliability: Time and flexibility 

sufficient to allow for planning, 

implementation and the integration of 

actions needed to address reliability 

while achieving the required emissions 

reductions. 

In addition, the final guidelines add a 

requirement, based on substantial input 

from experts in the energy field, for 

states to demonstrate that they have 

considered electric system reliability in 

developing their state plans. The final 

rule also offers additional opportunities 

that support electric system reliability, 

including opportunities for trading 

within and between states. The final 

guidelines also make clear that states 

can adjust their plans in the event that 

reliability challenges arise that need to 

be remedied by amending the state plan. 

In addition, the final rule includes a 

reliability safety valve to address 

situations where, because of an 

unanticipated catastrophic event, there 

is a conflict between the requirements 

imposed on an affected unit and the 

maintenance of reliability. 

(9) Approaches for addressing 

employment concerns. 

Some commenters brought to our 

attention the concerns of workers, their 

families and communities, particularly 

in coal-producing regions and states, 

that the ongoing shift toward lowercarbon electricity generation that the 

final rule reflects will cause harm to 

communities that are dependent on 

coal. Others had concerns about 

whether new jobs created as a result of 

actions taken pursuant to the final rule 

will allow for overall economic 

development. In the final rule, the EPA 

encourages states, in designing their 

state plans, to consider the effects of 

their plans on employment and overall 

economic development to assure that 

the opportunities for economic growth 

and jobs that the plans offer are 

manifest. We also identify federal 

programs, including the multi-agency 

Partnerships for Opportunity and 

Workforce and Economic Revitalization 

(POWER) Initiative.15 The POWER 

Initiative is competitively awarding 

planning assistance and implementation 

grants with funding from the 

Department of Commerce, Department 

of Labor (DOL), Small Business 

Administration, and the Appalachian 

Regional Commission,16 whose mission 

is to assist communities affected by 

changes in the coal industry and the 

utility power sector. 

(10) Community and environmental 

justice considerations. 

Many community leaders, 

environmental justice advocates, faithbased organizations and others 

commented that the benefits of this rule 

must be shared broadly across society 

and that undue burdens should not be 

imposed on low-income ratepayers. We 

agree. The federal government is taking 

significant steps to help low-income 

families and individuals gain access to 

RE and demand-side EE through new 

initiatives involving, for example, 

increasing solar energy systems in 

federally subsidized homes and 

supporting solar systems for others with 

low incomes. The final rule ensures that 

bill-lowering measures such as demandside EE continue to be a major 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64677 

17 Intergovernmental Panel on Climate Change 

(IPCC) report, ‘‘Contribution of Working Group I to 

the Fourth Assessment Report of the 

Intergovernmental Panel on Climate Change,’’ 2007. 

Available at http://epa.gov/climatechange/

ghgemissions/global.html. 18From 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. 

Available at http://epa.gov/climatechange/

ghgemissions/usinventoryreport.html. 

19U.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/. 

20The President’s Climate Action Plan, June 

2013. http://www.whitehouse.gov/sites/default/

files/image/president27sclimateactionplan.pdf. 

21Presidential Memorandum—Power Sector 

Carbon Pollution Standards, June 25, 2013. http:// 

www.whitehouse.gov/the-press-office/2013/06/25/

presidential-memorandum-power-sector-carbonpollution-standards. 

compliance option. The CEIP will 

encourage early investment in these 

types of projects as well. In addition to 

carbon reduction benefits, we expect 

significant near- and long-term public 

health benefits in communities as 

conventional air pollutants are reduced 

along with GHGs. However, some 

stakeholders expressed concerns about 

the possibility of localized increases in 

emissions from some power plants as 

the utility industry complies with state 

plans, in particular in communities 

already disproportionately affected by 

air pollution. This rule sets expectations 

for states to engage with vulnerable 

communities as they develop their 

plans, so that impacts on these 

communities are considered as plans are 

designed. The EPA also encourages 

states to engage with workers in the 

utility power and related sectors, as well 

as their worker representatives, so that 

impacts on their communities may be 

considered. The EPA commits, once 

implementation is under way, to assess 

the impacts of this rule. Likewise, we 

encourage states to evaluate the effects 

of their plans to ensure that there are no 

disproportionate adverse impacts on 

their communities. 

5. Additional Context for This Final 

Rule 

a. Climate change impacts. This final 

rule is an important step in an essential 

series of long-term actions that are 

achieving and must continue to achieve 

the GHG emission reductions needed to 

address the serious threat of climate 

change, and constitutes a major 

commitment—and international 

leadership-by-doing—on the part of the 

U.S., one of the world’s largest GHG 

emitters. GHG pollution threatens the 

American public by leading to damaging 

and long-lasting changes in our climate 

that can have a range of severe negative 

effects on human health and the 

environment. CO2 is the primary GHG 

pollutant, accounting for nearly threequarters of global GHG emissions17 and 

82 percent of U.S. GHG emissions.18

The May 2014 report of the National 

Climate Assessment 19 concluded that 

climate change impacts are already 

manifesting themselves and imposing 

losses and costs. The report documents 

increases in extreme weather and 

climate events in recent decades, with 

resulting damage and disruption to 

human well-being, infrastructure, 

ecosystems, and agriculture, and 

projects continued increases in impacts 

across a wide range of communities, 

sectors, and ecosystems. New scientific 

assessments since 2009, when the EPA 

determined that GHGs pose a threat to 

human health and the environment (the 

‘‘Endangerment Finding’’), highlight the 

urgency of addressing the rising 

concentration of CO2 in the atmosphere. 

Certain groups, including children, the 

elderly, and the poor, are most 

vulnerable to climate-related effects. 

Recent studies also find that certain 

communities, including low-income 

communities and some communities of 

color (more specifically, populations 

defined jointly by ethnic/racial 

characteristics and geographic location), 

are disproportionately affected by 

certain climate change related impacts— 

including heat waves, degraded air 

quality, and extreme weather events— 

which are associated with increased 

deaths, illnesses, and economic 

challenges. Studies also find that 

climate change poses particular threats 

to the health, well-being, and ways of 

life of indigenous peoples in the U.S. 

b. The utility power sector. One of the 

strategies of the President’s Climate 

Action Plan is to reduce CO2 emissions 

from power plants.20 This is because 

fossil fuel-fired EGUs are by far the 

largest emitters of GHGs, primarily in 

the form of CO2. Among stationary 

sources in the U.S. and among fossil 

fuel-fired EGUs, coal-fired units are by 

far the largest emitters of GHGs. To 

accomplish the goal of reducing CO2

emissions from power plants, President 

Obama issued a Presidential 

Memorandum 21 that recognized the 

importance of significant and prompt 

action. The Memorandum directed the 

EPA to complete carbon pollution 

standards, regulations or guidelines, as 

appropriate, for new, modified, 

reconstructed and existing power 

plants, and in doing so to build on state 

leadership in moving toward a cleaner 

power sector. In this action and the 

concurrent CAA section 111(b) rule, the 

EPA is finalizing regulations to reduce 

GHG emissions from fossil fuel-fired 

EGUs. This CAA section 111(d) action 

builds on actions states and utilities are 

already taking to move toward cleaner 

generation of electric power. 

The utility power sector is unlike 

other industrial sectors. In other sectors, 

sources effectively operate 

independently and on a local-site scale, 

with control of their physical operations 

resting in the hands of their respective 

owners and operators. Pollution control 

standards, which focus on each source 

in a non-utility industrial source 

category, have reflected the standalone 

character of individual source 

investment decision-making and 

operations. 

In stark contrast, the utility power 

sector comprises a unique system of 

electricity resources, including the 

EGUs affected under these guidelines, 

that operate in a complex and 

interconnected grid where electricity 

generally flows freely (e.g., portions of 

the system cannot be easily isolated 

through the use of switches or valves as 

can be done in other networked systems 

like trains and pipeline systems). That 

grid is physically interconnected and 

operated on an integrated basis across 

large regions. In this interconnected 

system, system operators, whose 

decisions, protocols, and actions, to a 

significant extent, dictate the operations 

of individual EGUs and large ensembles 

of EGUs, must reliably balance supply 

and demand using available generation 

and demand-side resources, including 

EE, demand response and a wide range 

of low- and 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 supply 

and demand constantly being balanced 

to meet system needs. Each step of the 

process from the electric generator to 

the end user is highly regulated by 

multiple entities working in 

coordination and considering overall 

system reliability. For example, in an 

independent system operator (ISO) or 

regional transmission organization 

(RTO) with a centralized, organized 

capacity market, electric generators are 

paid to be available to run when 

needed, must bid into energy markets, 

must respond to dispatch instructions, 

and must have permission to schedule 

maintenance. The ISO/RTO dispatches 

resources in a way that maintains 

electric system reliability. 

The approach we take in the final 

guidelines—both in the way we defined 

the BSER and established the resulting 

emission performance rates, and in the 

ranges of options we created for states 


tkelley on DSK3SPTVN1PROD with BOOK 2
64678 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

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

Electric Power Systems, IEEE Press, at 159 (2d ed. 

2010). 

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

Electric Power Systems, IEEE Press, at 160 (2d ed. 

2010). 

24 Federal Power Comm’n v. Florida Power & 

Light Co., 404 U.S. 453, at 460 (1972) (quoting a 

Federal Power Commission hearing examiner, ‘‘ ‘If 

a housewife in Atlanta on the Georgia system turns 

on a light, every generator on Florida’s system 

almost instantly is caused to produce some quantity 

of additional electric energy which serves to 

maintain the balance in the interconnected system 

between generation and load.’ ’’) (citation omitted). 

See also New York v. FERC, 535 U.S. 1, at 7–8 

(2002) (stating that ‘‘any electricity that enters the 

grid immediately becomes a part of a vast pool of 

energy that is constantly moving in interstate 

commerce.’’) (citation omitted). In Federal Power 

Comm’n v. Southern California Edison Co., 376 

U.S. 205 (1964), the Supreme Court found that a 

sale for resale of electricity from Southern 

California Edison to the City of Colton, which took 

place solely in California, was under Federal Power 

Commission jurisdiction because some of the 

electricity that Southern California Edison marketed 

came from out of state. The Supreme Court stated 

that, ‘‘ ‘federal jurisdiction was to follow the flow 

of electric energy, an engineering and scientific, 

rather than a legalistic or governmental, test.’ ’’ Id. 

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

Federal Power Commission, 324 U.S. 515, 529 

(1945) (emphasis omitted). 

25SNL Energy. Data used with permission. 

Accessed on June 9, 2015. 

and affected EGUs—is consistent with, 

and in some ways mirrors, the 

interconnected, interdependent and 

highly regulated nature of the utility 

power sector, the daily operation of 

affected EGUs within this framework, 

and the critical role of utilities in 

providing reliable, affordable electricity 

at all times and in all places within this 

complex, regulated system. Thus, not 

only do these guidelines put a premium 

on providing as much flexibility and 

latitude as possible for states and 

utilities, they also recognize that a given 

EGU’s operations are determined by the 

availability and use of other generation 

resources to which it is physically 

connected and by the collective 

operating regime that integrates that 

individual EGU’s activity with other 

resources across the grid. 

In this integrated system, numerous 

entities have both the capability and the 

responsibility to maintain a reliable 

electric system. FERC, DOE, state public 

utility commissions, ISOs, RTOs, other 

planning authorities, and the North 

American Electric Reliability 

Corporation (NERC), all contribute to 

ensuring the reliability of the electric 

system in the U.S. Critical to this 

function are dispatch tools, applied 

primarily by RTOs, ISOs, and balancing 

authorities, that operate such that 

actions taken or costs incurred at one 

source directly affect or cause actions to 

occur at other sources. Generation, 

outages, and transmission changes in 

one part of the synchronous grid can 

affect the entire interconnected grid.22

The interconnection is such that ‘‘[i]f a 

generator is lost in New York City, its 

effect is felt in Georgia, Florida, 

Minneapolis, St. Louis, and New 

Orleans.’’ 23 The U.S. Supreme Court 

has explicitly recognized the 

interconnected nature of the electricity 

grid.24

The uniqueness of the utility power 

sector inevitably affects the way in 

which environmental regulations are 

designed. When the EPA promulgates 

environmental regulations that affect the 

utility power sector, as we have done 

numerous times over the past four 

decades, we do so with the awareness 

of the importance of the efficient and 

continuous, uninterrupted operation of 

the interconnected electricity system in 

which EGUs participate. We also keep 

in mind the unique product that this 

interconnected system provides— 

electricity services—and the critical role 

of this sector to the U.S. economy and 

to the fundamental well-being of all 

Americans. 

In the context of environmental 

regulation, Congress, the EPA and the 

states all have recognized—as we do in 

these final guidelines—that electricity 

production takes place, at least to some 

extent, interchangeably between and 

among multiple generation facilities and 

different types of generation. This is 

evidenced in the enactment or 

promulgation of pollution reduction 

programs, such as Title IV of the CAA, 

the NOX state implementation plan (SIP) 

Call, the Cross-State Air Pollution Rule 

(CSAPR), and the Regional Greenhouse 

Gas Initiative (RGGI). As these actions 

show, both Congress and the EPA have 

consistently tailored legislation and 

regulations affecting the utility power 

sector to its unique characteristics. For 

example, in Title IV of the Clean Air Act 

Amendments of 1990, Congress 

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 natural gas-fired units and 

RE. Similarly, in the NOX SIP Call, the 

Clean Air Interstate Rule (CAIR), and 

CSAPR, the EPA established pollution 

reduction programs focused on fossil 

fuel-fired EGUs and designed those 

programs with express recognition of 

the sector’s ability to shift generation 

among various EGUs. In this action, we 

continue that approach. Both the 

subcategory-specific emission 

performance rates, and the pathways 

offered to achieve them, reflect and are 

tailored to the unique characteristics of 

the utility power sector. 

The way that power is produced, 

distributed and used in the U.S. is 

already changing as a result of 

advancements in innovative power 

sector technologies and in the 

availability and cost of low-carbon fuel, 

RE and demand-side EE technologies, as 

well as economic conditions. These 

changes are taking place at a time when 

the average age of the coal-fired 

generating fleet is approaching that at 

which utilities and states undertake 

significant new investments to address 

aging assets. In 2025, the average age of 

the coal-fired generating fleet is 

projected to be 49 years old, and 20 

percent of those units would be more 

than 60 years old if they remain in 

operation at that time. Therefore, even 

in the absence of additional 

environmental regulation, states and 

utilities can be expected to be, and 

already are, making plans for and 

investing in the next generation of 

power production, simply because of 

the need to take account of the age of 

current assets and infrastructure. 

Historically, the industry has invested 

about $100 billion a year in capital 

improvements. These guidelines will 

help ensure that, as those necessary 

investments are being made, they are 

integrated with the need to address GHG 

pollution from the sector. 

At the same time, owners/operators of 

affected EGUs are already pursuing the 

types of measures contemplated in this 

rule. Out of 404 entities identified as 

owners or operators of affected EGUs, 

representing ownership of 82 percent of 

the total capacity of the affected EGUs, 

178 already own RE generating capacity 

in addition to fossil fuel-fired generating 

capacity. In fact, these entities already 

own aggregate amounts of RE generating 

capacity equal to 25 percent of the 

aggregate amounts of their affected EGU 

capacity.25 In addition, funding for 

utility EE programs has been growing 

rapidly, increasing from $1.6 billion in 

2006 to $6.3 billion in 2013. 

The final guidelines are based on, and 

reinforce, the actions already being 

taken by states and utilities to upgrade 

aging electricity infrastructure with 21st 

century technologies. The guidelines 

will ensure that these trends continue in 

ways that are consistent with the longterm planning and investment processes 

already used in the utility power sector. 

This final rule provides flexibility for 

states to build upon their progress, and 

the progress of cities and towns, in 

addressing GHGs, and minimizes 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64679 

additional requirements for existing 

programs where possible. It also allows 

states to pursue policies to reduce 

carbon pollution that: (1) Continue to 

rely on a diverse set of energy resources; 

(2) ensure electric system reliability; (3) 

provide affordable electricity; (4) 

recognize investments that states and 

power companies are already making; 

and (5) tailor plans to meet their 

respective energy, environmental and 

economic needs and goals, and those of 

their local communities. Thus, the final 

guidelines will achieve meaningful CO2

emission reductions while maintaining 

the reliability and affordability of 

electricity in the U.S. 

6. Projected National-Level Emission 

Reductions 

Under the final guidelines, the EPA 

projects annual CO2 reductions of 22 to 

23 percent below 2005 levels in 2020, 

28 to 29 percent below 2005 levels in 

2025, and 32 percent below 2005 levels 

in 2030. These guidelines will also 

result in important reductions in 

emissions of criteria air pollutants, 

including SO2, NOX, and directlyemitted fine particulate matter (PM2.5). 

A thorough discussion of the EPA’s 

analysis is presented in Section XI.A of 

this preamble and in Chapter 3 of the 

Regulatory Impact Analysis (RIA) 

included in the docket for this 

rulemaking. 

7. Costs and Benefits 

Actions taken to comply with the 

final guidelines will reduce emissions of 

CO2 and other air pollutants, including 

SO2, NOX, and directly emitted PM2.5

from the utility power sector. States will 

make the ultimate determination as to 

how the emission guidelines are 

implemented. Thus, all costs and 

benefits reported for this action are 

illustrative estimates. The illustrative 

costs and benefits are based upon 

compliance approaches that reflect a 

range of measures consisting of 

improved operations at EGUs, 

dispatching lower-emitting EGUs and 

zero-emitting energy sources, and 

increasing levels of end-use EE. 

Because of the range of choices 

available to states and the lack of a 

priori knowledge about the specific 

choices states will make in response to 

the final goals, the RIA for this final 

action presents two scenarios designed 

to achieve these goals, which we term 

the ‘‘rate-based’’ illustrative plan 

approach and the ‘‘mass-based’’ 

illustrative plan approach. 

In summary, we estimate the total 

combined climate benefits and health 

co-benefits for the rate-based approach 

to be $3.5 to $4.6 billion in 2020, $18 

to $28 billion in 2025, and $34 to $54 

billion in 2030 (3 percent discount rate, 

2011$). Total combined climate benefits 

and health co-benefits for the massbased approach are estimated to be $5.3 

to $8.1 billion in 2020, $19 to $29 

billion in 2025, and $32 to $48 billion 

in 2030 (3 percent discount rate, 2011$). 

A summary of the emission reductions 

and monetized benefits estimated for 

this rule at all discount rates is provided 

in Tables 15 through 22 of this 

preamble. 

The annual compliance costs are 

estimated using the Integrated Planning 

Model (IPM) and include demand-side 

EE program and participant costs as 

well as monitoring, reporting and 

recordkeeping costs. In 2020, total 

compliance costs of the final guidelines 

are approximately $2.5 billion (2011$) 

under the rate-based approach and $1.4 

billion (2011$) under the mass-based 

approach. In 2025, total compliance 

costs of the final guidelines are 

approximately $1.0 billion (2011$) 

under the rate-based approach and $3.0 

billion (2011$) under the mass-based 

approach. In 2030, total compliance 

costs of the final guidelines are 

approximately $8.4 billion (2011$) 

under the rate-based approach and $5.1 

billion (2011$) under the mass-based 

approach. 

The quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2020 are 

estimated to range from $1.0 billion to 

$2.1 billion (2011$) using a 3 percent 

discount rate (model average) under the 

rate-based approach and from $3.9 

billion to $6.7 billion (2011$) using a 3 

percent discount rate (model average) 

under the mass-based approach. In 

2025, the quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2025 are 

estimated to range from $17 billion to 

$27 billion (2011$) using a 3 percent 

discount rate (model average) under the 

rate-based approach and from $16 

billion to $26 billion (2011$) using a 3 

percent discount rate (model average) 

under the mass-based approach. In 

2030, the quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2030 are 

estimated to range from $26 billion to 

$45 billion (2011$) using a 3 percent 

discount rate (model average) under the 

rate-based approach and from $26 

billion to $43 billion (2011$) using a 3 

percent discount rate (model average) 

under the mass-based approach. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64680 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

TABLE 1—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE FINAL GUIDELINES

IN 2020, 2025, AND 2030 a UNDER THE RATE-BASED ILLUSTRATIVE PLAN APPROACH

[Billions of 2011$] 

Rate-based approach, 2020 

3% Discount rate 7% Discount 

rate 

Climate benefits b ....................................................................... $2.8 

Air pollution health co-benefits c ................................................ $0.70 to $1.8 ............................................................................ $0.64 to $1.7. 

Total Compliance Costs d .......................................................... $2.5 ........................................................................................... $2.5. 

Net Monetized Benefits e ........................................................... $1.0 to $2.1 .............................................................................. $1.0 to $2.0. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

Rate-based approach, 2025 

Climate benefits b ....................................................................... $10 

Air pollution health co-benefits c ................................................ $7.4 to $18 ............................................................................... $6.7 to $16. 

Total Compliance Costs d .......................................................... $1.0 ........................................................................................... $1.0. 

Net Monetized Benefits e ........................................................... $17 to $27 ................................................................................ $16 to $25. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

Rate-based approach, 2030 

Climate benefits b ....................................................................... $20 

Air pollution health co-benefits c ................................................ $14 to $34 ................................................................................ $13 to $31. 

Total Compliance Costs d .......................................................... $8.4 ........................................................................................... $8.4. 

Net Monetized Benefits e ........................................................... $26 to $45 ................................................................................ $25 to $43. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in 

non-CO2 GHG emissions. Also, different discount rates are applied to SC–CO2 than to the other estimates because CO2 emissions are long-lived 

and subsequent damages occur over many years. The benefit estimates in this table are based on the average SCC estimated for a 3 percent 

discount rate, however we emphasize the importance and value of considering the full range of SC–CO2 values. As shown in the RIA, climate 

benefits are also estimated using the other three SC–CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th 

percentile at 3 percent). The SC–CO2 estimates are year-specific and increase over time. cThe 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. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a 

discount rate of approximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program and participant costs. eThe 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64681 

TABLE 2—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE FINAL GUIDELINES

IN 2020, 2025 AND 2030 a UNDER THE MASS-BASED ILLUSTRATIVE PLAN APPROACH

[Billions of 2011$] 

Mass-based approach, 2020 

3% Discount rate 7% Discount 

rate 

Climate benefits b ....................................................................... $3.3 

Air pollution health co-benefits c ................................................ $2.0 to $4.8 .............................................................................. $1.8 to $4.4. 

Total Compliance Costs d .......................................................... $1.4 ........................................................................................... $1.4. 

Net Monetized Benefits e ........................................................... $3.9 to $6.7 .............................................................................. $3.7 to $6.3. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

Mass-based approach, 2025 

Climate benefits b $12 

Air pollution health co-benefits c ................................................ $7.1 to $17 ............................................................................... $6.5 to $16. 

Total Compliance Costs d .......................................................... $3.0 ........................................................................................... $3.0. 

Net Monetized Benefits e ........................................................... $16 to $26 ................................................................................ $15 to $24. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

Mass-based approach, 2030 

Climate benefits b ....................................................................... $20 

Air pollution health co-benefits c ................................................ $12 to $28 ................................................................................ $11 to $26. 

Total Compliance Costs d .......................................................... $5.1 ........................................................................................... $5.1. 

Net Monetized Benefits e ........................................................... $26 to $43 ................................................................................ $25 to $40. 

Non-monetized Benefits ............................................................ Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, 

and mercury. 

Visibility impairment. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe 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 year-specific and increase over time. cThe 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. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a 

discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program 

and participant costs. eThe 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64682 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

26Although 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.html. 

27A 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. 

28The 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). 

29National Research Council, Climate 

Stabilization Targets, p.3. 

30 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

There are additional important 

benefits that the EPA could not 

monetize. Due to current data and 

modeling limitations, our estimates of 

the benefits from reducing CO2

emissions do not include important 

impacts like ocean acidification or 

potential tipping points in natural or 

managed ecosystems. The unquantified 

benefits also include climate benefits 

from reducing emissions of non-CO2

GHGs (e.g., nitrous oxide and 

methane) 26 and co-benefits from 

reducing direct exposure to SO2, NOX, 

and HAP (e.g., mercury and hydrogen 

chloride), as well as from reducing 

ecosystem effects and visibility 

impairment. 

We project employment gains and 

losses relative to base case for different 

types of labor, including construction, 

plant operation and maintenance, coal 

and natural gas production, and 

demand-side EE. In 2030, we project a 

net decrease in job-years of about 31,000 

under the rate-based approach and 

34,000 under the mass-based 

approach 27 for construction, plant 

operation and maintenance, and coal 

and natural gas and a gain of 52,000 to 

83,000 jobs in the demand-side EE 

sector under either approach. Actual 

employment impacts will depend upon 

measures taken by states in their state 

plans and the specific actions sources 

take to comply. 

Based upon the foregoing, it is clear 

that the monetized benefits of this rule 

are substantial and far outweigh the 

costs. 

B. Organization and Approach for This 

Rule 

This final rule establishes the EPA’s 

emission guidelines for states to follow 

in developing plans to reduce CO2

emissions from the utility power sector. 

Section II of this preamble provides 

background information on climate 

change impacts from GHG emissions, 

GHG emissions from fossil fuel-fired 

EGUs, the utility power sector, the CAA 

section 111(d) requirements, EPA 

actions prior to this final action, 

outreach and consultations, and the 

number and extent of comments 

received. In section III of the preamble, 

we present a summary of the rule 

requirements and the legal basis for 

these. Section IV explains the EPA 

authority to regulate CO2 and EGUs, 

identifies affected EGUs, and describes 

the proposed treatment of source 

categories. Section V describes the 

agency’s determination of the BSER 

using three building blocks and our key 

considerations in making the 

determination. Section VI provides the 

subcategory-specific emission 

performance rates, and section VII 

provides equivalent statewide ratebased and mass-based goals. Section 

VIII then describes state plan 

approaches and the requirements, and 

flexibilities, for state plans, followed by 

section IX, in which considerations for 

communities are described. Interactions 

between this final rule and other EPA 

programs and rules are discussed in 

section X. Impacts of the proposed 

action are then described in section XI, 

followed by a discussion of statutory 

and executive order reviews in section 

XII and the statutory authority for this 

action in section XIII. 

We note that this rulemaking is being 

promulgated concurrently with two 

related actions in this issue of the 

Federal Register: The final NSPS for 

CO2 emissions from newly constructed, 

modified, and reconstructed EGUs, 

which is being promulgated under CAA 

section 111(b), and the proposed federal 

plan and model rules. These 

rulemakings have their own rulemaking 

dockets. 

II. Background 

In this section, we discuss climate 

change impacts from GHG emissions, 

both on public health and public 

welfare. We also present information 

about GHG emissions from fossil fuelfired EGUs, the challenges associated 

with controlling carbon dioxide 

emissions, the uniqueness of the utility 

power sector, and recent and continuing 

trends and transitions in the utility 

power sector. In addition, we briefly 

describe CAA regulations for power 

plants, provide highlights of 

Congressional awareness of climate 

change and international agreements 

and actions, and summarize statutory 

and regulatory requirements relevant to 

this rulemaking. In addition, we provide 

background information on the EPA’s 

June 18, 2014 Clean Power Plan 

proposal, the November 4, 2014 

supplemental proposal, and other 

actions associated with this 

rulemaking,28 followed by information 

on stakeholder outreach and 

consultations and the comments that the 

EPA received prior to issuing this final 

rulemaking. 

A. Climate Change Impacts From GHG 

Emissions 

According to the National Research 

Council, ‘‘Emissions of CO2 from the 

burning of fossil fuels have ushered in 

a new epoch where human activities 

will largely determine the evolution of 

Earth’s climate. Because CO2 in the 

atmosphere is long lived, it can 

effectively lock Earth and future 

generations into a range of impacts, 

some of which could become very 

severe. Therefore, emission reduction 

choices made today matter in 

determining impacts experienced not 

just over the next few decades, but in 

the coming centuries and millennia.’’ 29

In 2009, based on a large body of 

robust and compelling scientific 

evidence, the EPA Administrator issued 

the Endangerment Finding under CAA 

section 202(a)(1).30 In the Endangerment 

Finding, the Administrator found that 

the current, elevated concentrations of 

GHGs in the atmosphere—already at 

levels unprecedented in human 

history—may reasonably be anticipated 

to endanger public health and welfare of 

current and future generations in the 

U.S. We summarize these adverse 

effects on public health and welfare 

briefly here. 

1. Public Health Impacts Detailed in the 

2009 Endangerment Finding 

Climate change caused by human 

emissions of GHGs threatens the health 

of Americans in multiple ways. By 

raising average temperatures, climate 

change increases the likelihood of heat 

waves, which are associated with 

increased deaths and illnesses. While 

climate change also increases the 

likelihood of reductions in cold-related 

mortality, evidence indicates that the 

increases in heat mortality will be larger 

than the decreases in cold mortality in 

the U.S. Compared to a future without 

climate change, climate change is 

expected to increase ozone pollution 

over broad areas of the U.S., especially 

on the highest ozone days and in the 

largest metropolitan areas with the 

worst ozone problems, and thereby 

increase the risk of morbidity and 

mortality. Climate change is also 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64683 

31 IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part B: Regional 

Aspects. Contribution of Working Group II to the 

Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, 

D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. 

Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 

Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 

MacCracken, P.R. Mastrandrea, and L.L. White 

(eds.)]. Cambridge University Press, Cambridge, p. 

1581. https://www.ipcc.ch/report/ar5/wg2/. 

expected to cause more intense 

hurricanes and more frequent and 

intense storms and heavy precipitation, 

with impacts on other areas of public 

health, such as the potential for 

increased deaths, injuries, infectious 

and waterborne diseases, and stressrelated 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 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 

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 major assessments by the 

USGCRP, the IPCC, and the NRC of the 

National Academies to provide the 

technical and scientific information to 

inform the Administrator’s judgment 

regarding the question of whether GHGs 

endanger public health and welfare. 

These assessments addressed the 

scientific issues that the EPA was 

required to examine, were 

comprehensive in their coverage of the 

GHG and climate change issues, and 

underwent rigorous and exacting peer 

review by the expert community, as 

well as rigorous levels of U.S. 

government review. 

The findings of the recent scientific 

assessments confirm and strengthen the 

conclusion that GHGs endanger public 

health, now and in the future. The 

NCA3 indicates that human health in 

the U.S. will be impacted by ‘‘increased 

extreme weather events, wildfire, 

decreased air quality, threats to mental 

health, and illnesses transmitted by 

food, water, and disease-carriers such as 

mosquitoes and ticks.’’ The most recent 

assessments now have greater 

confidence that climate change will 

influence production of pollen that 

exacerbates asthma and other allergic 

respiratory diseases such as allergic 

rhinitis, as well as effects on 

conjunctivitis and dermatitis. Both the 

NCA3 and the IPCC AR5 found that 

increasing temperature has lengthened 

the allergenic pollen season for 

ragweed, and that increased CO2 by 

itself can elevate production of plantbased allergens. 

The NCA3 also finds that climate 

change, in addition to chronic stresses 

such as extreme poverty, is negatively 

affecting indigenous peoples’ health in 

the U.S. through impacts such as 

reduced access to traditional foods, 

decreased water quality, and increasing 

exposure to health and safety hazards. 

The IPCC AR5 finds that climate 

change-induced warming in the Arctic 

and resultant changes in environment 

(e.g., permafrost thaw, effects on 

traditional food sources) have 

significant impacts, observed now and 

projected, on the health and 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.’’ 31 In addition, increasing 

temperatures and loss of Arctic sea ice 

increases the risk of drowning for those 

engaged in traditional hunting and 

fishing. 

The NCA3 concludes that children’s 

unique physiology and developing 

bodies contribute to making them 

particularly vulnerable to climate 

change. Impacts on children are 

expected from heat waves, air pollution, 

infectious and waterborne illnesses, and 

mental health effects resulting from 

extreme weather events. The IPCC AR5 

indicates that children are among those 

especially susceptible to most allergic 

diseases, as well as health effects 


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32National Research Council, Understanding 

Earth’s Deep Past, p. 1. 

33 Id., p.138. 

34NRC, 2011: National Security Implications of 

Climate Change for U.S. Naval Forces. The National 

Academies Press, p. 28. 

associated with heat waves, storms, and 

floods. The IPCC finds that additional 

health concerns may arise in low 

income households, especially those 

with children, if climate change reduces 

food availability and increases prices, 

leading to food insecurity within 

households. 

Both the NCA3 and IPCC AR5 

conclude that climate change will 

increase health risks facing the elderly. 

Older people are at much higher risk of 

mortality during extreme heat events. 

Pre-existing health conditions also make 

older adults susceptible to cardiac and 

respiratory impacts of air pollution and 

to more severe consequences from 

infectious and waterborne diseases. 

Limited mobility among older adults 

can also increase health risks associated 

with extreme weather and floods. 

The new assessments also confirm 

and strengthen the conclusion that 

GHGs endanger public welfare, and 

emphasize the urgency of reducing GHG 

emissions due to their projections that 

show GHG concentrations climbing to 

ever-increasing levels in the absence of 

mitigation. The NRC assessment 

Understanding Earth’s Deep Past 

projected that, without a reduction in 

emissions, CO2 concentrations by the 

end of the century would increase to 

levels that the Earth has not experienced 

for more than 30 million years.32 In fact, 

that assessment stated that ‘‘the 

magnitude and rate of the present GHG 

increase place the climate system in 

what could be one of the most severe 

increases in radiative forcing of the 

global climate system in Earth 

history.’’ 33 Because of these 

unprecedented changes, several 

assessments state that we may be 

approaching critical, poorly understood 

thresholds. As stated in the assessment, 

‘‘As Earth continues to warm, it may be 

approaching a critical climate threshold 

beyond which rapid and potentially 

permanent—at least on a human 

timescale—changes not anticipated by 

climate models tuned to modern 

conditions may occur.’’ The NRC 

Abrupt Impacts report analyzed abrupt 

climate change in the physical climate 

system and abrupt impacts of ongoing 

changes that, when thresholds are 

crossed, can cause abrupt impacts for 

society and ecosystems. The report 

considered destabilization of the West 

Antarctic Ice Sheet (which could cause 

3–4 m of potential sea level rise) as an 

abrupt climate impact with unknown 

but probably low probability of 

occurring this century. The report 

categorized a decrease in ocean oxygen 

content (with attendant threats to 

aerobic marine life); increase in 

intensity, frequency, and duration of 

heat waves; and increase in frequency 

and intensity of extreme precipitation 

events (droughts, floods, hurricanes, 

and major storms) as climate impacts 

with moderate risk of an abrupt change 

within this century. The NRC Abrupt 

Impacts report also analyzed the threat 

of rapid state changes in ecosystems and 

species extinctions as examples of an 

irreversible impact that is expected to be 

exacerbated by climate change. Species 

at most risk include those whose 

migration potential is limited, whether 

because they live on mountaintops or 

fragmented habitats with barriers to 

movement, or because climatic 

conditions are changing more rapidly 

than the species can move or adapt. 

While the NRC determined that it is not 

presently possible to place exact 

probabilities on the added contribution 

of climate change to extinction, they did 

find that there was substantial risk that 

impacts from climate change could, 

within a few decades, drop the 

populations in many species below 

sustainable levels thereby committing 

the species to extinction. Species within 

tropical and subtropical rainforests such 

as the Amazon and species living in 

coral reef ecosystems were identified by 

the NRC as being particularly vulnerable 

to extinction over the next 30 to 80 

years, as were species in high latitude 

and high elevation regions. Moreover, 

due to the time lags inherent in the 

Earth’s climate, the NRC Climate 

Stabilization Targets assessment notes 

that the full warming from any given 

concentration of CO2 reached will not 

be fully realized for several centuries, 

underscoring that emission activities 

today carry with them climate 

commitments far into the future. 

Future temperature changes will 

depend on what emission path the 

world follows. In its high emission 

scenario, the IPCC AR5 projects that 

global temperatures by the end of the 

century will likely be 2.6 °C to 4.8 °C 

(4.7 to 8.6 °F) warmer than today. 

Temperatures on land and in northern 

latitudes will likely warm even faster 

than the global average. However, 

according to the NCA3, significant 

reductions in emissions would lead to 

noticeably less future warming beyond 

mid-century, and therefore less impact 

to public health and welfare. 

While rainfall may only see small 

globally and annually averaged changes, 

there are expected to be substantial 

shifts in where and when that 

precipitation falls. According to the 

NCA3, regions closer to the poles will 

see more precipitation, while the dry 

subtropics are expected to expand 

(colloquially, this has been summarized 

as wet areas getting wetter and dry 

regions getting drier). In particular, the 

NCA3 notes that the western U.S., and 

especially the Southwest, is expected to 

become drier. This projection is 

consistent with the recent observed 

drought trend in the West. At the time 

of publication of the NCA, even before 

the last 2 years of extreme drought in 

California, tree ring data was already 

indicating that the region might be 

experiencing its driest period in 800 

years. Similarly, the NCA3 projects that 

heavy downpours are expected to 

increase in many regions, with 

precipitation events in general 

becoming less frequent but more 

intense. This trend has already been 

observed in regions such as the 

Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate 

Stabilization Targets assessment found 

that the area burned by wildfire is 

expected to grow by 2 to 4 times for 1 

°C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 

out of 10 summers would be warmer 

than all but the 5 percent of warmest 

summers today, leading to increased 

frequency, duration, and intensity of 

heat waves. Extrapolations by the NCA 

also indicate that Arctic sea ice in 

summer may essentially disappear by 

mid-century. Retreating snow and ice, 

and emissions of carbon dioxide and 

methane released from thawing 

permafrost, will also amplify future 

warming. 

Since the 2009 Endangerment 

Finding, the USGCRP NCA3, and 

multiple NRC assessments have 

projected future rates of sea level rise 

that are 40 percent larger to more than 

twice as large as the previous estimates 

from the 2007 IPCC 4th Assessment 

Report due in part to improved 

understanding of the future rate of melt 

of the Antarctic and Greenland Ice 

sheets. The NRC Sea Level Rise 

assessment projects a global sea level 

rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) 

by 2100, the NRC National Security 

Implications assessment suggests that 

‘‘the Department of the Navy should 

expect roughly 0.4 to 2 meters [1.3 to 6.6 

feet] global average sea-level rise by 

2100,’’ 34 and the NRC Climate 

Stabilization Targets assessment states 

that an increase of 3 °C will lead to a 

sea level rise of 0.5 to 1 meter (1.6 to 

3.3 feet) by 2100. These assessments 

continue to recognize that there is 


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35Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts 

in the United States: The Third National Climate 

Assessment. U.S. Global Change Research Program, 

p. 9. 

36Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts 

in the United States: The Third National Climate 

Assessment. U.S. Global Change Research Program, 

p. 17. 

37 IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part A: Global and 

Sectoral Aspects. Contribution of Working Group II 

to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, 

C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. 

Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796. 

https://www.ipcc.ch/report/ar5/wg2/. 

38NRC, 2010: Ocean Acidification: A National 

Strategy to Meet the Challenges of a Changing 

Ocean. The National Academies Press, p. 5. 

39 Ibid. 

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.’’ 35 Also, 

because of the inertia of the oceans, sea 

level rise will continue for centuries 

after GHG concentrations have 

stabilized (though more slowly than it 

would have otherwise). Additionally, 

there is a threshold temperature above 

which the Greenland ice sheet will be 

committed to inevitable melting: 

According to the NCA, some recent 

research has suggested that even present 

day CO2 levels could be sufficient to 

exceed that threshold. 

In general, climate change impacts are 

expected to be unevenly distributed 

across different regions of the U.S. and 

have a greater impact on certain 

populations, such as indigenous peoples 

and the poor. The NCA3 finds climate 

change impacts such as the rapid pace 

of temperature rise, coastal erosion and 

inundation related to sea level rise and 

storms, ice and snow melt, and 

permafrost thaw are affecting 

indigenous people in the U.S. 

Particularly in Alaska, critical 

infrastructure and traditional 

livelihoods are threatened by climate 

change and, ‘‘[i]n parts of Alaska, 

Louisiana, the Pacific Islands, and other 

coastal locations, climate change 

impacts (through erosion and 

inundation) are so severe that some 

communities are already relocating from 

historical homelands to which their 

traditions and cultural identities are 

tied.’’ 36 The IPCC AR5 notes, ‘‘Climaterelated hazards exacerbate other 

stressors, often with negative outcomes 

for livelihoods, especially for people 

living in poverty (high confidence). 

Climate-related hazards affect poor 

people’s lives directly through impacts 

on livelihoods, reductions in crop 

yields, or destruction of homes and 

indirectly through, for example, 

increased food prices and food 

insecurity.’’ 37

Carbon dioxide in particular has 

unique impacts on ocean ecosystems. 

The NRC Climate Stabilization Targets 

assessment found that coral bleaching 

will increase due both to warming and 

ocean acidification. Ocean surface 

waters have already become 30 percent 

more acidic over the past 250 years due 

to absorption of CO2 from the 

atmosphere. According to the NCA3, 

this acidification will reduce the ability 

of organisms such as corals, krill, 

oysters, clams, and crabs to survive, 

grow, and reproduce. The NRC 

Understanding Earth’s Deep Past 

assessment notes four of the five major 

coral reef crises of the past 500 million 

years were caused by acidification and 

warming that followed GHG increases of 

similar magnitude to the emissions 

increases expected over the next 

hundred years. The NRC Abrupt 

Impacts assessment specifically 

highlighted similarities between the 

projections for future acidification and 

warming and the extinction at the end 

of the Permian which resulted in the 

loss of an estimated 90 percent of 

known species. Similarly, the NRC 

Ocean Acidification assessment finds 

that ‘‘[t]he chemistry of the ocean is 

changing at an unprecedented rate and 

magnitude due to anthropogenic carbon 

dioxide emissions; the rate of change 

exceeds any known to have occurred for 

at least the past hundreds of thousands 

of years.’’ 38 The assessment notes that 

the full range of consequences is still 

unknown, but the risks ‘‘threaten coral 

reefs, fisheries, protected species, and 

other natural resources of value to 

society.’’ 39

Events outside the U.S., as also 

pointed out in the 2009 Endangerment 

Finding, will also have relevant 

consequences. The NRC Climate and 

Social Stress assessment concluded that 

it is prudent to expect that some climate 

events ‘‘will produce consequences that 

exceed the capacity of the affected 

societies or global systems to manage 

and that have global security 

implications serious enough to compel 

international response.’’ The NRC 

National Security Implications 

assessment recommends preparing for 

increased needs for humanitarian aid; 

responding to the effects of climate 

change in geopolitical hotspots, 

including possible mass migrations; and 

addressing changing security needs in 

the Arctic as sea ice retreats. 

In addition to future impacts, the 

NCA3 emphasizes that climate change 

driven by human emissions of GHGs is 

already happening now and it is 

happening in the U.S. According to the 

IPCC AR5 and the NCA3, there are a 

number of climate-related changes that 

have been observed recently, and these 

changes are projected to accelerate in 

the future. The planet warmed about 

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

extremely likely (>95 percent 

probability) that human influence was 

the dominant cause of the observed 

warming since the mid-20th century, 

and likely (>66 percent probability) that 

human influence has more than doubled 

the probability of occurrence of heat 

waves in some locations. In the 

Northern Hemisphere, the last 30 years 

were likely the warmest 30 year period 

of the last 1400 years. U.S. average 

temperatures have similarly increased 

by 1.3 to 1.9 degrees F since 1895, with 

most of that increase occurring since 

1970. Global sea levels rose 0.19 m (7.5 

inches) from 1901 to 2010. Contributing 

to this rise was the warming of the 

oceans and melting of land ice. It is 

likely that 275 gigatons per year of ice 

melted from land glaciers (not including 

ice sheets) since 1993, and that the rate 

of loss of ice from the Greenland and 

Antarctic ice sheets increased 

substantially in recent years, to 215 

gigatons per year and 147 gigatons per 

year respectively since 2002. For 

context, 360 gigatons of ice melt is 

sufficient to cause global sea levels to 

rise 1 mm. Annual mean Arctic sea ice 

has been declining at 3.5 to 4.1 percent 

per decade, and Northern Hemisphere 

snow cover extent has decreased at 

about 1.6 percent per decade for March 

and 11.7 percent per decade for June. 

Permafrost temperatures have increased 

in most regions since the 1980s, by up 

to 3 °C (5.4 °F) in parts of 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 


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

co2_annmean_mlo.txt. 

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

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

of the Climate in 2013. Bull. Amer. Meteor. Soc., 

95 (7), S1–S238. 

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

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

National Academies Press. 

and delivery, causing supply 

disruptions, and compromise other 

essential infrastructure such as water 

and transportation systems. 

In addition to the changes 

documented in the assessment 

literature, there have been other climate 

milestones of note. In 2009, the year of 

the Endangerment Finding, the average 

concentration of CO2 as measured on 

top of Mauna Loa was 387 parts per 

million, far above preindustrial 

concentrations of about 280 parts per 

million.40 The average concentration in 

2013, the last full year before this rule 

was proposed, was 396 parts per 

million. The average concentration in 

2014 was 399 parts per million. And the 

monthly concentration in April of 2014 

was 401 parts per million, the first time 

a monthly average has exceeded 400 

parts per million since record keeping 

began at Mauna Loa in 1958, and for at 

least the past 800,000 years.41 Arctic sea 

ice has continued to decline, with 

September of 2012 marking a new 

record low in terms of Arctic sea ice 

extent, 40 percent below the 1979–2000 

median. Sea level has continued to rise 

at a rate of 3.2 mm per year (1.3 inches/ 

decade) since satellite observations 

started in 1993, more than twice the 

average rate of rise in the 20th century 

prior to 1993.42 And 2014 was the 

warmest year globally in the modern 

global surface temperature record, going 

back to 1880; this now means 19 of the 

20 warmest years have occurred in the 

past 20 years, and except for 1998, the 

ten warmest years on record have 

occurred since 2002.43 The first months 

of 2015 have also been some of the 

warmest on record. 

These assessments and observed 

changes make it clear that reducing 

emissions of GHGs across the globe is 

necessary in order to avoid the worst 

impacts of climate change, and 

underscore the urgency of reducing 

emissions now. The NRC Committee on 

America’s Climate Choices listed a 

number of reasons ‘‘why it is imprudent 

to delay actions that at least begin the 

process of substantially reducing 

emissions.’’ 44 For example: 

• The faster emissions are reduced, 

the lower the risks posed by climate 

change. Delays in reducing emissions 

could commit the planet to a wide range 

of adverse impacts, especially if the 

sensitivity of the climate to GHGs is on 

the higher end of the estimated range. 

• Waiting for unacceptable impacts to 

occur before taking action is imprudent 

because the effects of GHG emissions do 

not fully manifest themselves for 

decades and, once manifest, many of 

these changes will persist for hundreds 

or even thousands of years. 

• In the committee’s judgment, the 

risks associated with doing business as 

usual are a much greater concern than 

the risks associated with engaging in 

strong response efforts. 

4. Observed and Projected U.S. Regional 

Changes 

The NCA3 assessed the climate 

impacts in 8 regions of the U.S., noting 

that changes in physical climate 

parameters such as temperatures, 

precipitation, and sea ice retreat were 

already having impacts on forests, water 

supplies, ecosystems, flooding, heat 

waves, and air quality. Moreover, the 

NCA3 found that future warming is 

projected to be much larger than recent 

observed variations in temperature, with 

precipitation likely to increase in the 

northern states, decrease in the southern 

states, and with the heaviest 

precipitation events projected to 

increase everywhere. 

In the Northeast, temperatures 

increased almost 2 °F from 1895 to 

2011, precipitation increased by about 5 

inches (10 percent), and sea level rise of 

about a foot has led to an increase in 

coastal flooding. The 70 percent 

increase in the amount of rainfall falling 

in the 1 percent of the most intense 

events is a larger increase in extreme 

precipitation than experienced in any 

other U.S. region. 

In the future, if emissions continue 

increasing, the Northeast is expected to 

experience 4.5 to 10 °F of warming by 

the 2080s. This will lead to more heat 

waves, coastal and river flooding, and 

intense precipitation events. The 

southern portion of the region is 

projected to see 60 additional days per 

year above 90 °F by mid-century. Sea 

levels in the Northeast are expected to 

increase faster than the global average 

because of subsidence, and changing 

ocean currents may further increase the 

rate of sea level rise. Specific 

vulnerabilities highlighted by the NCA 

include large urban populations 

particularly vulnerable to climaterelated 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 tropicalstorm induced storm-surge. The NCA 

also highlighted infrastructure 

vulnerable to inundation in coastal 

metropolitan areas, potential 

agricultural impacts from increased rain 

in the spring delaying planting or 

damaging crops or increased heat in the 

summer leading to decreased yields and 

increased water demand, and shifts in 

ecosystems leading to declines in iconic 

species in some regions, such as cod 

and lobster south of Cape Cod. 

In the Southeast, average annual 

temperature during the last century 

cycled between warm and cool periods. 

A warm peak occurred during the 1930s 

and 1940s followed by a cool period and 

temperatures then increased again from 

1970 to the present by an average of 

2 °F. There have been increasing 

numbers of days above 95 °F and nights 

above 75 °F, and decreasing numbers of 

extremely cold days since 1970. Daily 

and five-day rainfall intensities have 

also increased, and summers have been 

either increasingly dry or extremely wet. 

Louisiana has already lost 1,880 square 

miles of land in the last 80 years due to 

sea level rise and other contributing 

factors. 

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 

ground-level ozone in urban areas. 

Although projected warming for some 

parts of the region by the year 2100 are 

generally smaller than for other regions 

of the U.S., projected warming for 

interior states of the region are larger 

than coastal regions by 1 °F to 2 °F. 

Projections further suggest that globally 

there will be 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 1.3 °F 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 


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altered water availability from 

snowpack across parts of the region. 

Snowpack in the Northwest is an 

important freshwater source for the 

region. More precipitation falling as rain 

instead of snow has reduced the 

snowpack, and warmer springs have 

corresponded to earlier snowpack 

melting and reduced streamflows during 

summer months. Drier conditions have 

increased the extent of wildfires in the 

region. 

Average annual temperatures are 

projected to increase by 3.3 °F to 9.7 °F 

by the end of the century (depending on 

future global GHG emissions), with the 

greatest warming expected during the 

summer. Continued increases in global 

GHG emissions are projected to result in 

up to a 30 percent decrease in summer 

precipitation. Earlier snowpack melt 

and lower summer stream flows are 

expected by the end of the century and 

will affect drinking water supplies, 

agriculture, ecosystems, and 

hydropower production. Warmer waters 

are expected to increase disease and 

mortality in important fish species, 

including Chinook and sockeye salmon. 

Ocean acidification also threatens 

species such as oysters, with the 

Northwest coastal waters already being 

some of the most acidified worldwide 

due to coastal upwelling and other local 

factors. Forest pests are expected to 

spread and wildfires burn larger areas. 

Other high-elevation ecosystems are 

projected to be lost because they can no 

longer survive the climatic conditions. 

Low lying coastal areas, including the 

cities of Seattle and Olympia, will 

experience heightened risks of sea level 

rise, erosion, seawater inundation and 

damage to infrastructure and coastal 

ecosystems. 

In Alaska, temperatures have changed 

faster than anywhere else in the U.S. 

Annual temperatures increased by about 

3 °F in the past 60 years. Warming in 

the winter has been even greater, rising 

by an average of 6 °F. Arctic sea ice is 

thinning and shrinking in area, with the 

summer minimum ice extent now 

covering only half the area it did when 

satellite records began in 1979. Glaciers 

in Alaska are melting at some of the 

fastest rates on Earth. Permafrost soils 

are also warming and beginning to thaw. 

Drier conditions have contributed to 

more large wildfires in the last 10 years 

than in any previous decade since the 

1940s, when recordkeeping began. 

Climate change impacts are harming the 

health, safety and livelihoods of Native 

Alaskan communities. 

By the end of this century, continued 

increases in GHG emissions are 

expected to increase temperatures by 10 

to 12 °F in the northernmost parts of 

Alaska, by 8 to 10 °F in the interior, and 

by 6 to 8 °F across the rest of the state. 

These increases will exacerbate ongoing 

arctic sea ice loss, glacial melt, 

permafrost thaw and increased wildfire, 

and threaten humans, ecosystems, and 

infrastructure. Precipitation is expected 

to increase to varying degrees across the 

state, however warmer air temperatures 

and a longer growing season are 

expected to result in drier conditions. 

Native Alaskans are expected to 

experience declines in economically, 

nutritionally, and culturally important 

wildlife and plant species. Health 

threats will also increase, including loss 

of clean water, saltwater intrusion, 

sewage contamination from thawing 

permafrost, and northward extension of 

diseases. Wildfires will increasingly 

pose threats to human health as a result 

of smoke and direct contact. Areas 

underlain by ice-rich permafrost across 

the state are likely to experience ground 

subsidence and extensive damage to 

infrastructure as the permafrost thaws. 

Important ecosystems will continue to 

be affected. Surface waters and wetlands 

that are drying provide breeding habitat 

for millions of waterfowl and shorebirds 

that winter in the lower 48 states. 

Warmer ocean temperatures, 

acidification, and declining sea ice will 

contribute to changes in the location 

and availability of commercially and 

culturally important marine fish. 

In the Southwest, temperatures are 

now about 2 °F higher than the past 

century, and are already the warmest 

that region has experienced in at least 

600 years. The NCA notes that there is 

evidence that climate-change induced 

warming on top of recent drought has 

influenced tree mortality, wildfire 

frequency and area, and forest insect 

outbreaks. Sea levels have risen about 7 

or 8 inches in this region, contributing 

to inundation of Highway 101 and 

backup of seawater into sewage systems 

in the San Francisco area. 

Projections indicate that the 

Southwest will warm an additional 5.5 

to 9.5 °F over the next century if 

emissions continue to increase. Winter 

snowpack in the Southwest is projected 

to decline (consistent with the record 

lows from this past winter), reducing 

the reliability of surface water supplies 

for cities, agriculture, cooling for power 

plants, and ecosystems. Sea level rise 

along the California coast will worsen 

coastal erosion, increase flooding risk 

for coastal highways, bridges, and lowlying airports, pose a threat to 

groundwater supplies in coastal cities 

such as Los Angeles, and increase 

vulnerability to floods for hundreds of 

thousands of residents in coastal areas. 

Climate change will also have impacts 

on the high-value specialty crops grown 

in the region as a drier climate will 

increase demands for irrigation, more 

frequent heat waves will reduce yields, 

and decreased winter chills may impair 

fruit and nut production for trees in 

California. Increased drought, higher 

temperatures, and bark beetle outbreaks 

are likely to contribute to continued 

increases in wildfires. The highly 

urbanized population of the Southwest 

is vulnerable to heat waves and water 

supply disruptions, which can be 

exacerbated in cases where high use of 

air conditioning triggers energy system 

failures. 

The rate of warming in the Midwest 

has markedly accelerated over the past 

few decades. Temperatures rose by more 

than 1.5 °F from 1900 to 2010, but 

between 1980 and 2010 the rate of 

warming was three times faster than 

from 1900 through 2010. 

Precipitation generally increased over 

the last century, with much of the 

increase driven by intensification of the 

heaviest rainfalls. Several types of 

extreme weather events in the Midwest 

(e.g., heat waves and flooding) have 

already increased in frequency and/or 

intensity due to climate change. 

In the future, if emissions continue 

increasing, the Midwest is expected to 

experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. 

Though projections of changes in total 

precipitation vary across the regions, 

more precipitation is expected to fall in 

the form of heavy downpours across the 

entire region, leading to an increase in 

flooding. Specific vulnerabilities 

highlighted by the NCA include longterm decreases in agricultural 

productivity, changes in the 

composition of the region’s forests, 

increased public health 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 midcentury. 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 


tkelley on DSK3SPTVN1PROD with BOOK 2
64688 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

45The emission data presented in this section of 

the preamble (Section II.B) are in metric tons, in 

keeping with reporting requirements for the GHGRP 

and the U.S. GHG Inventory. Note that the massbased state goals presented in section VII of this 

preamble, and discussed elsewhere in this 

preamble, are presented in short tons. 

46 ‘‘Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990—2013’’, Report EPA 430–R–15– 

004, United States Environmental Protection 

Agency, April 15, 2015. http://epa.gov/climate

change/ghgemissions/usinventoryreport.html. 

47U.S. EPA Greenhouse Gas Reporting Program 

Dataset, see http://www.epa.gov/ghgreporting/ghg

data/reportingdatasets.html. 

48Sinks are a physical unit or process that stores 

GHGs, such as forests or underground or deep sea 

reservoirs of carbon dioxide. 

49From Table ES–4 of ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2013’’, 

Report EPA 430–R–15–004, U.S. Environmental 

Protection Agency, April 15, 2015. http://epa.gov/ 

climatechange/ghgemissions/

usinventoryreport.html. 

50The energy sector includes all greenhouse gases 

resulting from stationary and mobile energy 

activities, including fuel combustion and fugitive 

fuel emissions. 

51From Table ES–2 ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2013’’, 

agricultural practices, and negative 

impacts on local plant and animal 

species from habitat fragmentation, 

wildfires, and changes in the timing of 

flowering or pest patterns. Communities 

that are already the most vulnerable to 

weather and climate extremes will be 

stressed even further by more frequent 

extreme events occurring within an 

already highly variable climate system. 

In Hawaii, other Pacific islands, and 

the Caribbean, rising air and ocean 

temperatures, shifting rainfall patterns, 

changing 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 Rinco ́n 

is being eroded at a rate of 3.3 feet per 

year. Freshwater supplies are already 

constrained and will become more 

limited on many islands. Saltwater 

intrusion associated with sea level rise 

will reduce the quantity and quality of 

freshwater in coastal aquifers, especially 

on low islands. In areas where 

precipitation does not increase, 

freshwater supplies will be adversely 

affected as air temperature rises. 

Warmer oceans are leading to 

increased coral bleaching events and 

disease outbreaks in coral reefs, as well 

as changed distribution patterns of tuna 

fisheries. Ocean acidification will 

reduce coral growth and health. 

Warming and acidification, combined 

with existing stresses, will strongly 

affect coral reef fish communities. For 

Hawaii and the Pacific islands, future 

sea surface temperatures are projected to 

increase 2.3 °F by 2055 and 4.7 °F by 

2090 under a scenario that assumes 

continued increases in emissions. Ocean 

acidification is also taking place in the 

region, which adds to ecosystem stress 

from increasing temperatures. Ocean 

acidity has increased by about 30 

percent since the pre-industrial era and 

is projected to further increase by 37 

percent to 50 percent from present 

levels by 2100. 

The NCA also discussed impacts that 

occur along the coasts and in the oceans 

adjacent to many regions, and noted that 

other impacts occur across regions and 

landscapes in ways that do not follow 

political boundaries. 

B. GHG Emissions From Fossil FuelFired EGUs 45

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 

fuel-fired 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 Sinks 46

(the U.S. GHG Inventory). 

The EPA implements a separate 

program under 40 CFR part 98 called 

the Greenhouse Gas Reporting 

Program 47 (GHGRP) that requires 

emitting facilities over threshold 

amounts of GHGs to report their 

emissions to the EPA annually. Using 

data from the GHGRP, this section also 

places emissions from fossil fuel-fired 

EGUs in the context of the total 

emissions reported to the GHGRP from 

facilities in the other largest-emitting 

industries. 

The EPA prepares the official U.S. 

GHG Inventory to comply with 

commitments under the United Nations 

Framework Convention on Climate 

Change (UNFCCC). This inventory, 

which includes recent trends, is 

organized by industrial sectors. It 

provides the information in Table 3 

below, which presents total U.S. 

anthropogenic emissions and sinks 48 of 

GHGs, including CO2 emissions, for the 

years 1990, 2005 and 2013. 

TABLE 3—U.S. GHG EMISSIONS AND SINKS BY SECTOR

[Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)] 49

Sector 1990 2005 2013 

Energy 50 ...................................................................................................................................... 5,290.5 6,273.6 5,636.6 

Industrial Processes and Product Use ........................................................................................ 342.1 367.4 359.1 

Agriculture .................................................................................................................................... 448.7 494.5 515.7 

Land Use, Land-Use Change and Forestry ................................................................................ 13.8 25.5 23.3 

Waste ........................................................................................................................................... 206.0 189.2 138.3 

Total Emissions .................................................................................................................... 6,301.1 7,350.2 6,673.0 

Land Use, Land-Use Change and Forestry (Sinks) .................................................................... (775.8) (911.9) (881.7) 

Net Emissions (Sources and Sinks) ............................................................................................ 5,525.2 6,438.3 5,791.2 

Total fossil energy-related CO2

emissions (including both stationary 

and mobile sources) are the largest 

contributor to total U.S. GHG emissions, 

representing 77.3 percent of total 2013 

GHG emissions.51 In 2013, fossil fuel 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64689 

Report EPA 430–R–15–004, United States 

Environmental Protection Agency, April 15, 2015. 

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

usinventoryreport.html. 

52From 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. 

53From 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/usinventory

report.html. 

54U.S. EPA Greenhouse Gas Reporting Program 

Dataset as of August 18, 2014. http://

ghgdata.epa.gov/ghgp/main.do. 

55Lackner et al., ‘‘Comparative Impacts of Fossil 

Fuels and Alternative Energy Sources’’, Issues in 

Environmental Science and Technology (2010). 

56This includes NAAQS and HAPs, based on the 

following table: (see table above). 

It should be noted that PM2.5 is included in the 

amounts for PM10. Lead, another NAAQS pollutant, 

is emitted in the amounts of approximately 1,000 

tons per year, and, in light of that relatively small 

quantity, was excluded from this analysis. 

Ammonia (NH3) is included because it is a 

precursor to PM2.5 secondary formation. Note that 

one short ton is equivalent to 0.907185 metric ton. 

57 In addition, emissions of non-CO2 GHGs totaled 

1.168 billion metric tons of carbon-dioxide 

equivalents (CO2e) in 2013. See Table ES–2, 

Executive Summary, 1990–2013 Inventory of U.S. 

Greenhouse Gas Emissions and Sinks. http://

www.epa.gov/climatechange/Downloads/

ghgemissions/US-GHG-Inventory-2015-ChapterExecutive-Summary.pdf. This includes emissions of 

methane, nitrous oxide, and fluorinated GHGs 

(hydrofluorocarbons, perfluorocarbons, sulfur 

hexafluoride, and nitrogen trifluoride). In the total, 

the emissions of each non-CO2 GHG have been 

translated from metric tons of that gas into metric 

tons of CO2e by multiplying the metric tons of the 

gas by the global warming potential (GWP) of the 

gas. (The GWP of a gas is a measure of the ability 

of one kilogram of that gas to trap heat in earth’s 

atmosphere compared to one kilogram of CO2.) 

combustion by the utility power 

sector—entities that burn fossil fuel and 

whose primary business is the 

generation of electricity—accounted for 

38.3 percent of all energy-related CO2

emissions.52 Table 4 below presents 

total CO2 emissions from fossil fuelfired EGUs, for years 1990, 2005 and 

2013. 

TABLE 4—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS

[MMT CO2] 53

GHG emissions 1990 2005 2013 

Total CO2 from fossil fuel-fired EGUs ......................................................................................... 1,820.8 2,400.9 2,039.8 

—from coal ........................................................................................................................... 1,547.6 1,983.8 1,575.0 

—from natural gas ................................................................................................................ 175.3 318.8 441.9 

—from petroleum .................................................................................................................. 97.5 97.9 22.4 

In addition to preparing the official 

U.S. GHG Inventory to present 

comprehensive total U.S. GHG 

emissions and comply with 

commitments under the UNFCCC, the 

EPA collects detailed GHG emissions 

data from the largest emitting facilities 

in the U.S. through its Greenhouse Gas 

Reporting Program (GHGRP). Data 

collected by the GHGRP from large 

stationary sources in the industrial 

sector show that the utility power sector 

emits far greater CO2 emissions than any 

other industrial sector. Table 5 below 

presents total GHG emissions in 2013 

for the largest emitting industrial sectors 

as reported to the GHGRP. As shown in 

Table 4 and Table 5, respectively, CO2

emissions from fossil fuel-fired EGUs 

are nearly three times as large as the 

total reported GHG emissions from the 

next ten largest emitting industrial 

sectors in the GHGRP database 

combined. 

TABLE 5—DIRECT GHG EMISSIONS

REPORTED TO GHGRP BY LARGEST

EMITTING INDUSTRIAL SECTORS

[MMT CO2e] 54

Industrial sector 2013 

Petroleum Refineries .................. 176.7 

Onshore Oil & Gas Production ... 94.8 

Municipal Solid Waste Landfills .. 93.0 

Iron & Steel Production .............. 84.2 

Cement Production ..................... 62.8 

Natural Gas Processing Plants .. 59.0 

Petrochemical Production ........... 52.7 

Hydrogen Production .................. 41.9 

Underground Coal Mines ........... 39.8 

Food Processing Facilities ......... 30.8 

C. Challenges in Controlling Carbon 

Dioxide Emissions 

Carbon dioxide is a unique air 

pollutant and controlling it presents 

unique challenges. CO2 is emitted in 

enormous quantities, and those 

quantities, coupled with the fact that 

CO2 is relatively unreactive, make it 

much more difficult to mitigate by 

measures or technologies that are 

typically utilized within an existing 

power plant. Measures that may be used 

to limit CO2 emissions would include 

efficiency improvements, which have 

thermodynamic limitations and carbon 

capture and sequestration (CCS), which 

is energy resource intensive. 

Unlike other air pollutants which are 

results of trace impurities in the fuel, 

products of incomplete or inefficient 

combustion, or combustion byproducts, 

CO2 is an inherent product of clean, 

efficient combustion of fossil fuels, and 

therefore is an unavoidable product 

generated in enormous quantities, far 

greater than any other air pollutant.55 In 

fact, CO2 is emitted in far greater 

quantities than all other air pollutants 

combined. Total emissions of all nonGHG air pollutants in the U.S., from all 

sources, in 2013, were 121 million 

metric tons.56 57

Pollutant 2013 tons 

(million short tons) Reference 

CO ....................................................... 69.758 Trends file (http://www.epa.gov/ttnchie1/trends/). 

NOX ..................................................... 13.072 ′′ 

PM10 ..................................................... 20.651 ′′ 

SO2 ...................................................... 5.098 ′′ 

VOC ..................................................... 17.471 ′′ 

NH3 ...................................................... 4.221 ′′ 

HAPS ................................................... 3.641 2011 NEI version 2 (http://www.epa.gov/ttn/chief/net/2011inventory.html). 

Total .............................................. 133.912 


tkelley on DSK3SPTVN1PROD with BOOK 2
64690 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

58From 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. 

59U.S. EPA, Greenhouse Gas Inventory Data 

Explorer, http://www.epa.gov/climatechange/

ghgemissions/inventoryexplorer/#allsectors/allgas/

gas/current. 

60As another point of comparison, except for 

carbon dioxide, SO2 and NOX are the largest air 

pollutant emissions from coal-fired power plants. 

Over the past decade, U.S. power plants have 

emitted more than 200 times as much CO2 as they 

have emitted SO2 and NOX. See de Gouw et al., 

‘‘Reduced emissions of CO2, NOX, and SO2 from 

U.S. power plants owing to switch from coal to 

natural gas with combined cycle technology,’’ 

Earth’s Future (2014). 

61Each atom of carbon in the fuel combines with 

2 atoms of oxygen in the air. 

62Seinfeld J. and Pandis S., Atmospheric 

Chemistry and Physics: From Air Pollution to 

Climate Change (1998). 

63The fact that CO2 is unreactive means that it 

is primarily removed from the atmosphere by 

dissolving in oceans or by being converted into 

biomass by plants. Herzog, H., ‘‘Scaling up carbon 

dioxide capture and storage: From megatons to 

gigatons’’, Energy Economics (2011). 

64Regulatory Assistance Project (RAP), Electricity 

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

at http://www.raponline.org/document/download/

id/645. 

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

Electric Power Systems, IEEE Press, at 2–4 (2d ed. 

2010). 

66Casazza, 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. 67Burn, An Energy Journal, The Electricity Grid: 

A History, available at http://

burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). 68The 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. 

69New York v. Federal Energy Regulatory 

Commission, 535 U.S. 1, 5 (2002) (citation omitted). 

70Public Utils. Comm’n of Rhode Island v. 

Attleboro Steam & Elec. Co., 273 U.S. 83 (1927). 

71Public Utils. Comm’n of Rhode Island v. 

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

72 16 U.S.C. 824(b)(1). 

73 16 U.S.C. 824d. 

As noted above, total emissions of CO2

from coal-fired power plants alone—the 

largest stationary source emitter—were 

1.575 billion metric tons in that year,58

and total emissions of CO2 from all 

sources were 5.5 billion metric tons.59 60

Carbon makes up the majority of the 

mass of coal and other fossil fuels, and 

for every ton of carbon burned, more 

than 3 tons of CO2 is produced.61 In 

addition, unlike many of the other air 

pollutants that react with sunlight or 

chemicals in the atmosphere, or are 

rained out or deposited on surfaces, CO2

is relatively unreactive and difficult to 

remove directly from the 

atmosphere.62 63

CO2’s huge quantities and lack of 

reactivity make it challenging to remove 

from the smokestack. Retrofitted 

equipment is required to capture the 

CO2 before transporting it to a storage 

site. However, the scale of infrastructure 

required to directly mitigate CO2

emissions from existing EGUs through 

CCS can be quite large and difficult to 

integrate into the existing fossil fuel 

infrastructure. These CCS techniques 

are discussed in more depth elsewhere 

in the preamble for this rule and for the 

section 111(b) rule for new sources that 

accompanies this rule. 

The properties of CO2 can be 

contrasted with those of a number of 

other pollutants which have more 

accessible mitigation options. For 

example, the NAAQS pollutants— 

which generally are emitted in the 

largest quantities of any of the other air 

pollutants, except for CO2—each have 

more accessible mitigation options. 

Sulfur dioxide (SO2) is the result of a 

contaminant in the fuel, and, as a result, 

it can be reduced by using low-sulfur 

coal or by using flue-gas desulfurization 

(FGD) technologies. Emissions of NOX

can be mitigated relatively easily using 

combustion control techniques (e.g., 

low-NOX burners) and by using 

downstream controls such as selective 

catalytic reduction (SCR) and selective 

non-catalytic reduction (SNCR) 

technologies. PM can be effectively 

mitigated using fabric filters, PM 

scrubbers, or electrostatic precipitators. 

Lead is part of particulate matter 

emissions and is controlled through the 

same devices. Carbon monoxide and 

VOCs are the products of incomplete 

combustion and can therefore be abated 

by more efficient combustion 

conditions, and can also be destroyed in 

the smokestack by the use of oxidation 

catalysts which complete the 

combustion process. Many air toxics are 

VOCs, such as polyaromatic 

hydrocarbons, and therefore can be 

abated in the same ways just described. 

But in every case, these pollutants can 

be controlled at the source much more 

readily than CO2 primarily because of 

the comparatively lower quantities that 

are produced, and also due to other 

attributes such as relatively greater 

reactivity and solubility. 

D. The Utility Power Sector 

1. A Brief History 

The modern American electricity 

system is one of the greatest engineering 

achievements of the past 100 years. 

Since the invention of the incandescent 

light bulb in the 1870s,64 electricity has 

become one of the major foundations for 

modern American life. Beginning with 

the first power station in New York City 

in 1882, each power station initially 

served a discrete set of consumers, 

resulting in small and localized 

electricity systems.65 During the early 

1900s, smaller systems consolidated, 

allowing generation resources to be 

shared over larger areas. Interconnecting 

systems have reduced generation 

investment costs and improved 

reliability.66 Local and state 

governments initially regulated these 

growing electricity systems with federal 

regulation coming later in response to 

public concerns about rising electricity 

costs.67

Initially, states had broad authority to 

regulate public utilities, but gradually 

federal regulation increased. In 1920, 

Congress passed the Federal Water 

Power Act, creating the Federal Power 

Commission (FPC) and providing for the 

licensing of hydroelectric facilities on 

U.S. government lands and navigable 

waters of the U.S.68 During this time 

period, the U.S. Supreme Court found 

that state authority to regulate public 

utilities is limited, holding that the 

Commerce Clause does not allow state 

regulation to directly burden interstate 

commerce.69 For example, in Public 

Utilities Commission of Rhode Island v. 

Attleboro Steam & Electric Company, 

Rhode Island sought to regulate the 

electricity rates that a Rhode Island 

generator was charging to a company in 

Massachusetts that resold the electricity 

to Attleboro, Massachusetts.70 The 

Supreme Court found that Rhode 

Island’s regulation was impermissible 

because it imposed a ‘‘direct burden 

upon interstate commerce.’’ 71 The 

Supreme Court held that this kind of 

interstate transaction was not subject to 

state regulation. However, because 

Congress had not yet passed legislation 

to make these types of transactions 

subject to federal regulation, this 

became known as the ‘‘Attleboro gap’’ in 

regulation. In 1935, Congress passed the 

Federal Power Act (FPA), giving the 

FPC jurisdiction over ‘‘the transmission 

of electric energy in interstate 

commerce’’ and ‘‘the sale of electric 

energy at wholesale in interstate 

commerce.’’ 72 Under FPA section 205, 

the FPC was tasked with ensuring that 

rates for jurisdictional services are just, 

reasonable, and not unduly 

discriminatory or preferential.73 FPA 

section 206 authorized the FPC to 

determine, after a hearing upon its own 

motion or in response to a complaint 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64691 

74 16 U.S.C. 824e. 

75Energy Information Administration, Natural 

Gas Act of 1938, available at http://www.eia.gov/

oil_gas/natural_gas/analysis_publications/

ngmajorleg/ngact1938.html. 

76Energy Information Administration, Natural 

Gas Act of 1938, available at http://www.eia.gov/

oil_gas/natural_gas/analysis_publications/

ngmajorleg/ngact1938.html. 

77Burn, An Energy Journal, The Electricity Grid: 

A History, available at http://

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

78Federal Energy Regulatory Commission, Energy 

Primer: A Handbook of Energy Market Basics, at 38 

(2012), available at http://www.ferc.gov/marketoversight/guide/energy-primer.pdf. 

79Federal Energy Regulatory Commission, Energy 

Primer: A Handbook of Energy Market Basics, at 38 

(2012), available at http://www.ferc.gov/marketoversight/guide/energy-primer.pdf. 

80Federal Energy Regulatory Commission, Energy 

Primer: A Handbook of Energy Market Basics, at 38 

(2012), available at http://www.ferc.gov/marketoversight/guide/energy-primer.pdf. 

81Federal Energy Regulatory Commission, Energy 

Primer: A Handbook of Energy Market Basics, at 38 

(2012), available at http://www.ferc.gov/marketoversight/guide/energy-primer.pdf. 

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

Electricity Business, Enerdynamics, at 94 (2012). 

83Maryland 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), available at http://

esm.versar.com/pprp/ceir13/toc.htm. 

84Pacific 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. 

85Pacific 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. 

86For 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-ahistory/ (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-pol-act/epactfinal-rpt.pdf (last visited Mar. 20, 2015). 

87The 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-final-rpt.pdf (last visited Mar. 20, 

2015). 

88These entities are also referred to as merchant 

generators. 

89Energy 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. 

90Regulatory Assistance Project (RAP), Electricity 

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

at http://www.raponline.org/document/download/

id/645. 

91 Investor-owned utilities are private companies 

that are financed by a combination of shareholder 

equity and bondholder debt. Regulatory Assistance 

Project (RAP), Electricity Regulation in the US: A 

Guide, at 9 (2011), available at http://

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

92Consumer-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. 

93Peter Fox-Penner, Electric Utility Restructuring: 

A Guide to the Competitive Era, Public Utility 

Reports, Inc., at 5, 34 (1997). ‘‘The extent of the 

power system’s short-run physical interdependence 

is remarkable, if not entirely unique. No other large, 

multi-stage industry is required to keep every single 

producer in a region—whether or not owned by the 

same company—in immediate synchronization 

with all other producers.’’ Id. at 34. ‘‘At an early 

date, those providing electric power recognized that 

peak use for one system often occurred at a different 

time from peak use in other systems. They also 

recognized that equipment failures occurred at 

different times in various systems. Analyses 

showed significant economic benefits from 

interconnecting systems to provide mutual 

assistance; the investment required for generating 

capacity could be reduced and reliability could be 

improved. This lead [sic] to the development of 

local, then regional, and subsequently three 

transmission grids that covered the U.S. and parts 

of Canada.’’ Casazza, J. and Delea, F., 

Understanding Electric Power Systems, IEEE Press, 

at 5–6 (2d ed. 2010). 

94Burn, 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/indus-act/reliability/blackout/

ch1-3.pdf. 

filed at the Commission, whether 

jurisdictional rates are just, reasonable, 

and not unduly discriminatory or 

preferential.74 In 1938, Congress passed 

the Natural Gas Act (NGA), giving the 

FPC jurisdiction over the transmission 

or sale of natural gas in interstate 

commerce.75 The NGA also gave the 

FPC the jurisdiction to ‘‘grant 

certificates allowing construction and 

operation of facilities used in interstate 

gas transmission and authorizing the 

provision of services.’’ 76 In 1977, the 

FPC became FERC after Congress passed 

the Department of Energy Organization 

Act. 

By the 1930s, regulated electric 

utilities that provided the major 

components of the electrical system— 

generation, transmission, and 

distribution—were common.77 These 

regulated monopolies are referred to as 

vertically-integrated utilities. 

As utilities built larger and larger 

electric generation plants, the cost per 

unit to generate electricity decreased.78

However, these larger plants were 

extremely capital intensive for any one 

company to fund.79 Some neighboring 

utilities solved this issue by agreeing to 

share electricity reserves when 

needed.80 These utilities began building 

larger transmission lines to deliver 

power in times when large generators 

experienced outages.81 Eventually, some 

utilities that were in reserve sharing 

agreements formed electric power pools 

to balance electric load over a larger 

area. Participating utilities gave control 

over scheduling and dispatch of their 

electric generation units to a system 

operator.82 Some power pools evolved 

into today’s RTOs and ISOs. 

In the past, electric utilities generally 

operated as state regulated monopolies, 

supplying end-use customers with 

generation, distribution, and 

transmission service.83 However, the 

ability of electric utilities to operate as 

natural monopolies came with 

consumer protection safeguards.84 ‘‘In 

exchange for a franchised, monopoly 

service area, utilities accept an 

obligation to serve—meaning there must 

be adequate supply to meet customers’ 

needs regardless of the cost.’’ 85 Under 

this obligation to serve, the utility 

agreed to provide service to any 

customer located within its service 

jurisdiction. 

On both a federal and state level, 

competition has entered the electricity 

sector to varying degrees in the last few 

decades.86 In the early 1990s, some 

states began to consider allowing 

competition to enter retail electric 

service.87 Federal and state efforts to 

allow competition in the electric utility 

industry have resulted in independent 

power producers (IPPs) 88 producing 

approximately 37 percent of net 

generation in 2013.89 Electric utilities in 

some states remain vertically integrated 

without retail competition from IPPs. 

Today, there are over 3,000 public, 

private, and cooperative utilities in the 

U.S.90 These utilities include both 

investor-owned utilities 91 and 

consumer-owned utilities.92

Over time, the grid slowly evolved 

into a complex, interconnected 

transmission system that allows electric 

generators to produce electricity that is 

then fed onto transmission lines at high 

voltages.93 These larger transmission 

lines are able to access generation that 

is located more remotely, with 

transmission lines crossing many miles, 

including state borders.94 Closer to end 

users, electricity is transformed into a 

lower voltage that is transported across 


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95Peter Fox-Penner, Electric Utility Restructuring: 

A Guide to the Competitive Era, Public Utility 

Reports, Inc., at 5 (1997). 

96U.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/indus-act/

reliability/blackout/ch1-3.pdf. 

97Regulatory Assistance Project (RAP), Electricity 

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

at http://www.raponline.org/document/download/

id/645. 

98Casazza, J. and Delea, F., Understanding 

Electric Power Systems, IEEE Press, at 159 (2d ed. 

2010). In an amicus brief to the Supreme Court, a 

group of electrical engineers, economists, and 

physicists specializing in electricity explained, 

‘‘Energy is transmitted, not electrons. Energy 

transmission is accomplished through the 

propagation of an electromagnetic wave. The 

electrons merely oscillate in place, but the energy— 

the electromagnetic wave—moves at the speed of 

light. The energized electrons making the lightbulb 

in a house glow are not the same electrons that were 

induced to oscillate in the generator back at the 

power plant. . . . Energy flowing onto a power 

network or grid energizes the entire grid, and 

consumers then draw undifferentiated energy from 

that grid. A networked grid flexes, and electric 

current flows, in conformity with physical laws, 

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

political boundaries. . . . The path taken by 

electric energy is the path of least resistance . . . 

or, more accurately, the paths of least 

resistance. . . . If a generator on the grid increases 

its output, the current flowing from the generator 

on all paths on the grid increases. These increases 

affect the energy flowing into each point in the 

network, which in turn leads to compensating and 

corresponding changes in the energy flows out of 

each point.’’ Brief Amicus Curiae of Electrical 

Engineers, Energy Economists and Physicists in 

Support of Respondents at 2, 8–9, 11, New York v. 

FERC, 535 U.S. 1 (2001) (No. 00–568). 

99 ‘‘Measures using demand-side resources 

comprise actions taken on the customer’s side of the 

meter to change the amount and/or timing of 

electricity use in ways that will provide benefits to 

the electricity supply system.’’ David Crossley, 

Regulatory Assistance Project (RAP), Effective 

Mechanisms to Increase the Use of Demand-Side 

Resources, at 9 (2013), available at 

www.raponline.org. 

100Energy efficiency is using less energy to 

provide the same or greater level of service. 

Demand-side energy efficiency refers to an 

extensive array of technologies, practices and 

measures that are applied throughout all sectors of 

the economy to reduce energy demand while 

providing the same, and sometimes better, level and 

quality of service. 

101 Demand response involves ‘‘[c]hanges in 

electric usage by demand-side resources from their 

normal consumption patterns in 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/indus-act/demand-response/dem-res-advmetering.asp. 

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

Electric Power Systems, IEEE Press, at 159 (2d ed. 

2010). 

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

Electric Power Systems, IEEE Press, at 160 (2d ed. 

2010). 104 Federal Power Comm’n v. Florida Power & 

Light Co., 404 U.S. 453, at 460 (1972) (quoting a 

Federal Power Commission hearing examiner, ‘‘‘If 

a housewife in Atlanta on the Georgia system turns 

on a light, every generator on Florida’s system 

almost instantly is caused to produce some quantity 

of additional electric energy which serves to 

maintain the balance in the interconnected system 

between generation and load.’’’) (citation omitted). 

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

(stating that ‘‘any electricity that enters the grid 

immediately becomes a part of a vast pool of energy 

that is constantly moving in interstate commerce.’’) 

(citation omitted). In Federal Power Comm’n v. 

Southern California Edison Co., 376 U.S. 205 

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

resale of electricity from Southern California Edison 

to the City of Colton, which took place solely in 

California, was under Federal Power Commission 

jurisdiction because some of the electricity that 

Southern California Edison marketed came from out 

of state. The Supreme Court stated that, ‘‘‘federal 

jurisdiction was to follow the flow of electric 

energy, an engineering and scientific, rather than a 

legalistic or governmental, test.’’’ Id. at 210 (quoting 

Connecticut Light & Power Co. v. Federal Power 

Commission, 324 U.S. 515, 529 (1945) (emphasis 

omitted)). 

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

Electric Power Systems, IEEE Press, at 214 (2d ed. 

2010). 

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

Electric Power Systems, IEEE Press, at 213 (2d ed. 

2010). 

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

Electric Power Systems, IEEE Press, at 213 (2d ed. 

2010). 

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

Electric Power Systems, IEEE Press, at 214 (2d ed. 

2010). 

localized transmission lines to homes 

and businesses.95 Localized 

transmission lines make up the 

distribution system. These three 

components of the electricity system— 

generation, transmission, and 

distribution—are closely related and 

must work in coordination to deliver 

electricity from the point of generation 

to the point of consumption. This 

interconnectedness is a fundamental 

aspect of the nation’s electricity system, 

requiring a complicated integration of 

all components of the system to balance 

supply and demand and a federal, state, 

and local regulatory network to oversee 

the physically interconnected network. 

Facilities planned and constructed in 

one segment can impact facilities and 

operations in other segments and vice 

versa. 

The North American electric grid has 

developed into a large, interconnected 

system.96 Electricity from a diverse set 

of generation resources such as natural 

gas, nuclear, coal, and renewables is 

distributed over high-voltage 

transmission lines divided across the 

continental U.S. into three synchronous 

interconnections—the Eastern 

Interconnection, Western 

Interconnection, and the Texas 

Interconnection.97 These three 

synchronous systems each act like a 

single machine.98 Diverse resources 

generate electricity that is transmitted 

and distributed through a complex 

system of interconnected components to 

industrial, business, and residential 

consumers. Unlike other industries 

where sources make operational 

decisions independently, the utility 

power sector is unique in that electricity 

system resources operate in a complex, 

interconnected grid system that is 

physically interconnected and operated 

on an integrated basis across large 

regions. Additionally, a federal, state, 

and local regulatory network oversees 

policies and practices that are applied to 

how the system is designed and 

operates. In this interconnected system, 

system operators must ensure that the 

amount of electricity available is 

precisely matched with the amount 

needed in real time. System operators 

have a number of resources potentially 

available to meet electricity demand, 

including electricity generated by 

electric generation units such as coal, 

nuclear, renewables, and natural gas, as 

well as demand-side resources,99 such 

as EE 100 and demand response.101

Generation, outages, and transmission 

changes in one part of the synchronous 

grid can affect the entire interconnected 

grid.102 The interconnection is such that 

‘‘[i]f a generator is lost in New York 

City, its affect is felt in Georgia, Florida, 

Minneapolis, St. Louis, and New 

Orleans.’’ 103 The U.S. Supreme Court 

has similarly recognized the 

interconnected nature of the electricity 

grid.104

Today, federal, state, and local 

entities regulate electricity providers.105

Overlaid on the physical electricity 

network is a regulatory network that has 

developed over the last century or more. 

This regulatory network ‘‘plays a vital 

role in the functioning of all other 

networks, sometimes providing specific 

rules for functioning while at other 

times providing restraints within which 

their operation must be conducted.’’ 106

This unique regulatory network results 

in an electricity grid that is both 

physically interconnected and 

connected through a network of 

regulation on the local, state, and 

federal levels. This regulation seeks to 

reconcile the fact that electricity is a 

public good with the fact that facilities 

providing that electricity are privately 

owned.107 While this regulation began 

on the state and local levels, federal 

regulation of the electricity system 

increased over time. With the passage of 

the EPAct 1992 and the EPAct 2005, the 

federal government’s role in electricity 

regulation greatly increased.108 ‘‘The 

role of the regulator now includes 

support for the development of open 


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

Electric Power Systems, IEEE Press, at 214 (2d ed. 

2010). 110Economic Dispatch: Concepts, Practices and 

Issues, FERC Staff Presentation to the Joint Board 

for the Study of Economic Dispatch, Palm Springs, 

California (Nov. 13, 2005), available at http://www.

ferc.gov/CalendarFiles/20051110172953-FERC%20

Staff%20Presentation.pdf. 111Federal 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. 109– 

58, 119 Stat. 594 (2005), section 1234(b), available 

at http://www.ferc.gov/industries/electric/indusact/joint-boards/final-cong-rpt.pdf. 

112 Variable costs also include costs associated 

with operation and maintenance and costs of 

operating a pollution control and/or emission 

allowance charges. 

113North American Electric Reliability 

Corporation, History of NERC, at 1 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/

History%20AUG13.pdf. 

114Federal Energy Regulatory Commission, 

Energy Primer: A Handbook of Energy Market 

Basics, at 39 (2012), available at http://

www.ferc.gov/market-oversight/guide/energyprimer.pdf. 

115The 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%20

AUG13.pdf. 

116North American Electric Reliability 

Corporation, History of NERC, at 2 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/

History%20AUG13.pdf. 

117North American Electric Reliability 

Corporation, History of NERC, at 4 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/

History%20AUG13.pdf. 

118North American Electric Reliability 

Corporation, History of NERC, at 3 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/

History%20AUG13.pdf. 

119U.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/indus-act/

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. 

120U.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/indus-act/

reliability/blackout/ch1-3.pdf. 

121 Mandatory Reliability Standards for the BulkPower System, Order No. 693, 118 FERC ¶ 61,218, 

at P 3 (2007) (citing 16 U.S.C. 824o(e)(3)). 

122Rules 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). 

123North American Electric Reliability 

Corporation, Frequently Asked Questions, at 2 (Aug. 

2013), available at http://www.nerc.com/About

NERC/Documents/NERC%20FAQs%20AUG13.pdf. 

and fair wholesale electric markets, 

ensuring equal access to the 

transmission system and more hands-on 

oversight and control of the planning 

and operating rules for the industry.’’ 109

2. Electric System Dispatch 

System operators typically dispatch 

the electric system through a process 

known as Security Constrained 

Economic Dispatch.110 Security 

Constrained Economic Dispatch has two 

components—economic generation of 

generation facilities and ensuring that 

the electric system remains reliable.111

Electricity demand varies across 

geography and time in response to 

numerous conditions, such that electric 

generators are constantly responding to 

changes in the most reliable and costeffective manner possible. The cost of 

operating electric generation varies 

based on a number of factors, such as 

fuel and generator efficiency. 

The decision to dispatch any 

particular electric generator depends 

upon the relative operating cost, or 

marginal cost, of generating electricity 

to meet the last increment of electric 

demand. Fuel is one common variable 

cost—especially for fossil-fueled 

generators. Coal plants will often have 

considerable variable costs associated 

with running pollution controls.112

Renewables, hydroelectric, and nuclear 

have little to no variable costs. If 

electricity demand decreases or 

additional generation becomes available 

on the system, this impacts how the 

system operator will dispatch the 

system. EGUs using technologies with 

relatively low variable costs, such as 

nuclear units and RE, are for economic 

reasons generally operated at their 

maximum output whenever they are 

available. When lower cost units are 

available to run, higher variable cost 

units, such as fossil-fuel generators, are 

generally the first to be displaced. 

In states with cost-of-service 

regulation of vertically-integrated 

utilities, the utilities themselves form 

the balancing authorities who determine 

dispatch based upon the lowest 

marginal cost. These utilities sometimes 

arrange to buy and sell electricity with 

other balancing authorities. RTOs and 

ISOs coordinate, control, and monitor 

electricity transmission systems to 

ensure cost-effective and reliable 

delivery of power, and they are 

independent from market participants. 

3. Reliability Considerations 

The reliability of the electric system 

has long been a focus of the electric 

industry and regulators. Industry 

developed a voluntary organization in 

the early 1960s that assisted with bulk 

power system coordination in the U.S. 

and Canada.113 In 1965, the 

northeastern U.S. and southeastern 

Ontario, Canada experienced the largest 

power blackout to date, impacting 30 

million people.114 In response to the 

1965 blackout and a Federal Power 

Commission recommendation,115

industry developed the National Electric 

Reliability Council (NERC) and nine 

reliability councils. The organization 

later became known as the North 

American Electric Reliability Council to 

recognize Canada’s participation.116 The 

North American Electric Reliability 

Council became the North American 

Electric Reliability Corporation in 

2007.117

In August 2003, North America 

experienced its worst blackout to date 

creating an outage in the Midwest, 

Northeast, and Ontario, Canada.118 This 

blackout was massive in scale impacting 

an area with an estimated 50 million 

people and 61,800 megawatts of electric 

load.119 The U.S. and Canada formed a 

joint task force to investigate the causes 

of the blackout and made 

recommendations to avoid similar 

outages in the future. One of the task 

force’s major recommendations was that 

the U.S. Congress should pass 

legislation making electric reliability 

standards mandatory and 

enforceable.120

Congress responded to this 

recommendation in EPAct 2005, adding 

a new section 215 to the Federal Power 

Act making reliability standards 

mandatory and enforceable and 

authorizing the creation of a new 

Electric Reliability Organization (ERO). 

Under this new system, FERC certifies 

an entity as the ERO. The ERO develops 

reliability standards, which are subject 

to FERC review and approval. Once 

FERC approves reliability standards the 

ERO may enforce those standards or 

FERC can do so independently.121 In 

2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as 

the ERO.122 ‘‘NERC develops and 

enforces Reliability Standards; monitors 

the Bulk-Power System; assesses 

adequacy annually via a 10-year forecast 

and winter and summer forecasts; audits 

owners, operators and users for 

preparedness; and educates and trains 

industry personnel.’’ 123

The U.S., Canada, and part of Mexico 

are divided up into eight reliability 


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124Federal Energy Regulatory Commission, 

Energy Primer: A Handbook of Energy Market 

Basics, at 49–50 (2012), available at http://

www.ferc.gov/market-oversight/guide/energyprimer.pdf. 

125Federal Energy Regulatory Commission, 

Energy Primer: A Handbook of Energy Market 

Basics, at 50 (2012), available at http://

www.ferc.gov/market-oversight/guide/energyprimer.pdf. 

126North 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. 

127North American Electric Reliability 

Corporation, Frequently Asked Questions, at 5 

(2013), available at http://www.nerc.com/About

NERC/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/Filings

Orders/us/Regional%20Delegation%20Agreements

%20DL/MRO_RDA_Effective_20130612.pdf. 

128North American Electric Reliability 

Corporation, Frequently Asked Questions, at 5 

(2013), available at http://www.nerc.com/

AboutNERC/Documents/NERC%20FAQs%

20AUG13.pdf. 

129 ISOs/RTOs plan for system needs by 

‘‘effectively managing the load forecasting, 

transmission planning, and system and resource 

planning functions.’’ For example, the New York 

Independent System Operator (NYISO) conducts 

reliability planning studies, which ‘‘are used to 

assess current reliability needs based on user trends 

and historical energy use.’’ NYISO, Planning 

Studies, available at http://www.nyiso.com/public/ 

markets_operations/services/planning/planning_

studies/index.jsp. See also PJM, Reliability 

Assessments, available at https://www.pjm.com/

planning/rtep-development/reliabilityassessments.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.’’). 

130U.S. Energy Information Administration, 

‘‘Table 7.2b Electricity Net Generation: Electric 

Power Sector’’ data from Monthly Energy Review 

May 2015, available at http://www.eia.gov/

totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

131U.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). 

132U.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). 

133Based 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 RE sources: 

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

biomass. Available at http://www.eia.gov/

electricity/monthly/epm_table_grapher.cfm?t=

epmt_6_03. 

134U.S. Energy Information Administration, 

‘‘Table 7.2b Electricity Net Generation: Electric 

Power Sector’’ data from Monthly Energy Review 

May 2015, available at http://www.eia.gov/

totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

135Bloomberg 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

%20America%20Factbook.pdf. Bloomberg gave 

projections for 2014 values, accounting for 

seasonality, based on latest monthly values from 

EIA (data available through October 2014). 

136Energy Information Administration, 

Electricity: Form EIA–860 detailed data (Feb. 17, 

2015), available at http://www.eia.gov/electricity/

data/eia860/. 

137EIA, 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 model-projected 

nuclear, coal, and NGCC projects. 

138American Society for Civil Engineers, 2013 

Report Card for America’s Infrastructure (2013), 

available at http://www.infrastructurereportcard 

.org/energy/. 

regional entities.124 These regional 

entities include Florida Reliability 

Coordinating Council (FRCC), Midwest 

Reliability Organization (MRO), 

Northeast Power Coordinating Council 

(NPCC), Reliability First Corporation 

(RFC), SERC Reliability Corporation 

(SERC), Southwest Power Pool, RE 

(SPP), Texas Reliability Entity (TRE), 

and Western Electricity Coordinating 

Council (WECC).125 Regional entity 

members come from all segments of the 

electric industry.126 NERC delegates 

authority, with FERC approval, to these 

regional entities to enforce reliability 

standards, both national and regional 

reliability standards, and engage in 

other standards-related duties delegated 

to them by NERC.127 NERC ensures that 

there is a consistency of application of 

delegated functions with appropriate 

regional flexibility.128 NERC divides the 

country into assessment areas and 

annually analyzes the reliability, 

adequacy, and associated risks that may 

affect the upcoming summer, winter, 

and long-term, 10-year period. Multiple 

other entities such as FERC, the 

Department of Energy, state public 

utility commissions, ISOs/RTOs,129 and 

other planning authorities also consider 

the reliability of the electric system. 

There are numerous remedies that can 

be utilized to solve a potential reliability 

problem, including long-term planning, 

transmission system upgrades, 

installation of new generating capacity, 

demand response, and other demand 

side actions. 

4. Modern Electric System Trends 

Today, the electricity sector is 

undergoing a period of intense change. 

Fossil fuels—such as coal, natural gas, 

and oil—have historically provided a 

large percentage of electricity in the 

U.S., along with nuclear power, with 

smaller amounts provided by other 

types of generation, including 

renewables such as wind, solar, and 

hydroelectric power. Coal provided the 

largest percentage of the fossil fuel 

generation.130 In recent years, the nation 

has seen a sizeable increase in 

renewable generation such as wind and 

solar, as well as a shift from coal to 

natural gas.131 In 2013, fossil fuels 

supplied 67 percent of U.S. 

electricity,132 but the amount of 

renewable generation capacity 

continued to grow.133 From 2007 to 

2014, use of lower- and zero-carbon 

energy sources such as wind and solar 

grew, while other major energy sources 

such as coal and petroleum generally 

experienced declines.134 Renewable 

electricity generation, including from 

large hydro-electric projects, grew from 

8 percent to 13 percent over that time 

period.135 Between 2000 and 2013, 

approximately 90 percent of new power 

generation capacity built in the U.S. 

came in the form of natural gas or RE 

facilities.136 In 2015, the U.S. Energy 

Information Administration (EIA) 

projected the need for 28.4 GW of 

additional base load or intermediate 

load generation capacity through 

2020.137 The vast majority of this new 

electric capacity (20.4 GW) is already 

under development (under construction 

or in advanced planning), with 

approximately 0.7 GW of new coal-fired 

capacity, 5.5 GW of new nuclear 

capacity, and 14.2 GW of new NGCC 

capacity already in development. 

While the change in the resource mix 

has accelerated in recent years, wind, 

solar, other renewables, and 

EEresources have been reliably 

participating in the electric sector for a 

number of years. This rapid 

development of non-fossil fuel resources 

is occurring as much of the existing 

power generation fleet in the U.S. is 

aging and in need of modernization and 

replacement. In 2025, the average age of 

the coal-fired generating fleet is 

projected to be 49 years old, and 20 

percent of those units would be more 

than 60 years old if they remain in 

operation at that time. In its 2013 Report 

Card for America’s Infrastructure, the 

American Society for Civil Engineers 

noted that ‘‘America relies on an aging 

electrical grid and pipeline distribution 

systems, some of which originated in 

the 1880s.’’ 138 While there has been an 


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139American Society for Civil Engineers, 2013 

Report Card for America’s Infrastructure (2013), 

available at http://www.infrastructurereportcard 

.org/energy/. 

140U.S. Energy Information Administration (EIA), 

Electric Power Monthly: Table 1.1 Net Generation 

by Energy Source: Total (All Sectors), 2005- 

February 2015 (2015), available athttp://

www.eia.gov/electricity/monthly/epm_table_

grapher.cfm?t=epmt_1_1 (last visited May 26, 

2015). 

141 Id. 

142U.S. Energy Information Administration (EIA), 

Annual Energy Outlook 2015 with Projections to 

2040, at 24–25 (2015), available at http://

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

According to the EIA, the reference case assumes, 

‘‘Real gross domestic product (GDP) grows at an 

average annual rate of 2.4% from 2013 to 2040, 

under the assumption that current laws and 

regulations remain generally unchanged throughout 

the projection period. North Sea Brent crude oil 

prices rise to $141/barrel (bbl) (2013 dollars) in 

2040.’’ Id. at 1. The EIA provides complete 

projection tables for the reference case in Appendix 

A of its report. 

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

Electric Power Systems, IEEE Press, at 220–221 (2d 

ed. 2010). 

144Cogeneration 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). 

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

Electric Power Systems, IEEE Press, at 220–221 (2d 

ed. 2010). 

146U.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). 

147Energy 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. 

148Non-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/. 

149Energy Information Administration, Monthly 

Energy Review, May 2015, Table 7.2b, available at 

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

sec7_6.pdf. 

150 ‘‘Global Renewable Energy Market Outlook.’’ 

Bloomberg New Energy Finance (Nov. 16, 2011), 

available at http://bnef.com/WhitePapers/

download/53. 

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

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

2012). 

152Energy Information Administration, Annual 

Energy Outlook 2015 with Projections to 2040, at 

25 (2015), available at http://www.eia.gov/

forecasts/aeo/pdf/0383(2015).pdf. 

153Energy Information Administration, Annual 

Energy Outlook 2015 with Projections to 2040, at 

ES–6 (2015), available at http://www.eia.gov/

forecasts/aeo/pdf/0383(2015).pdf (last visited May 

27, 2015). 

154Edison 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%20browser/ee_commission_history_report_

2–1–13.pdf. 

155American 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. 

156American 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. 

157American Council for an Energy-Efficient 

Economy, The 2013 State Energy Efficiency 

Continued 

increased investment in electric 

transmission infrastructure since 2005, 

the report also found that ‘‘ongoing 

permitting issues, weather events, and 

limited maintenance have contributed 

to an increasing number of failures and 

power interruptions.’’ 139 However, 

innovative technologies have 

increasingly entered the electric energy 

space, helping to provide new answers 

to how to meet the electricity needs of 

the nation. These new technologies can 

enable the nation to answer not just 

questions as to how to reliably meet 

electricity demand, but also how to 

meet electricity demand reliably and 

cost-effectively with the lowest possible 

emissions and the greatest efficiency. 

Natural gas has a long history of 

meeting electricity demand in the U.S., 

with a rapidly growing role as domestic 

supplies of natural gas have 

dramatically increased. Natural gas net 

generation increased by approximately 

32 percent between 2005 and 2014.140

In 2014, natural gas accounted for 

approximately 27 percent of net 

generation.141 EIA projects that this 

demand growth will continue with its 

Annual Energy Outlook 2015 (AEO 

2015) Reference case forecasting that 

natural gas will produce 31 percent of 

U.S. electric generation in 2040.142

Renewable sources of electric 

generation also have a history of 

meeting electricity demand in the U.S. 

and are expected to have an increasing 

role going forward. A series of energy 

crises provided the impetus for RE 

development in the early 1970s. The 

OPEC oil embargo in 1973 and oil crisis 

of 1979 caused oil price spikes, more 

frequent energy shortages, and 

significantly affected the national and 

global economy. In 1978, partly in 

response to fuel security concerns, 

Congress passed the Public Utilities 

Regulatory Policies Act (PURPA) which 

required local electric utilities to buy 

power from qualifying facilities 

(QFs).143 QFs were either cogeneration 

facilities 144 or small generation 

resources that use renewables such as 

wind, solar, biomass, geothermal, or 

hydroelectric power as their primary 

fuels.145 Through PURPA, Congress 

supported the development of more RE 

generation in the U.S. States have also 

taken a significant lead in requiring the 

development of renewable resources. In 

particular, a number of states have 

adopted renewable portfolio standards 

(RPS). As of 2013, 29 states and the 

District of Columbia have enforceable 

RPS or similar laws.146

Use of RE continues to grow rapidly 

in the U.S. In 2013, electricity generated 

from renewable technologies, including 

conventional hydropower, represented 

13 percent of total U.S. electricity, up 

from 9 percent in 2005.147 In 2013, U.S. 

non-hydro RE capacity for the total 

electric power industry exceeded 80,000 

MW, reflecting a fivefold increase in just 

15 years.148 In particular, there has been 

substantial growth in the wind and 

photovoltaic (PV) markets in the past 

decade. Since 2009, U.S. wind 

generation has tripled and solar 

generation has grown twenty-fold.149

The global market for RE is projected 

to grow to $460 billion per year by 

2030.150 RE growth is further 

encouraged by the significant amount of 

existing natural resources that can 

support RE production in the U.S.151 In 

the Energy Information Administration’s 

Annual Energy Outlook 2015, RE 

generation grows substantially from 

2013 to 2040 in the reference case and 

all alternative cases.152 In the reference 

case, RE generation increases by more 

than 70 percent from 2013 to 2040 and 

accounts for over one-third of new 

generation capacity.153

Price pressures caused by oil 

embargoes in the 1970s also brought the 

issues of conservation and EE to the 

forefront of U.S. energy policy.154 This 

trend continued in the early 1990s. EE 

has been utilized to meet energy 

demand to varying levels since that 

time. As of April 2014, 25 states 155 have 

‘‘enacted long-term (3+ years), binding 

energy savings targets, or energy 

efficiency resource standards 

(EERS).’’ 156 Funding for EE programs 

has grown rapidly in recent years, with 

budgets for electric efficiency programs 

totaling $5.9 billion in 2012.157


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Scorecard, at 17 (Nov. 2013), available at http://

aceee.org/sites/default/files/publications/

researchreports/e13k.pdf. 

158 42 U.S.C. 7651(b). 

159 42 U.S.C. 7651c (Table A). 

160 42 U.S.C. 7651c(b) and (d). 

161 42 U.S.C. 7651c(f) and (g). 

162U.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). 

163See 42 U.S.C. 7651d. 

164 42 U.S.C. 7651o. 

165 42 U.S.C. 7651g. 

166Such plans may simply state that the owner 

or operator expects to hold sufficient allowances or, 

in the case of alternative compliance methods, must 

provide a ‘‘comprehensive description of the 

schedule and means by which the unit will rely on 

one or more alternative methods of compliance in 

the manner and time authorized under [Title IV].’’ 

42 U.S.C. 7651g(b). 

167 42 U.S.C. 7410(a)(2)(D)(i)(I). 

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

S. Ct. 1584, 1600–01 (2014) (citing 42 U.S.C. 

7410(c)). 

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

170 70 FR 25162 (May 12, 2005). 

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

172 63 FR at 57377–78. 

173 63 FR at 57377–78. In addition to EGUs, the 

NOX SIP Call also set budgets based on highly costeffective emission reductions from certain other 

large sources. Id. 

174 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 

2000). 

175 70 FR at 25163. 

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

2006). 

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

modified on rehearing 550 F.3d 1176, 1178 (D.C. 

Cir. 2008). 

Advancements and innovation in 

power sector technologies provide the 

opportunity to address CO2 emission 

levels at affected power plants while at 

the same time improving the overall 

power system in the U.S. by lowering 

the carbon intensity of power 

generation, and ensuring a reliable 

supply of power at a reasonable cost. 

E. Clean Air Act Regulations for Power 

Plants 

In this section, we provide a general 

description of major CAA regulations 

for power plants. We refer to these in 

later sections of this preamble. 

1. Title IV Acid Rain Program 

The EPA’s Acid Rain Program, 

established in 1990 under Title IV of the 

CAA, addresses the presence of acidic 

compounds and their precursors (i.e., 

SO2 and NOX), in the atmosphere by 

targeting ‘‘the principal sources’’ of 

these pollutants through an SO2 capand-trade program for fossil-fuel fired 

power plants and through a technology 

based NOX emission limit for certain 

utility boilers. Altogether, Title IV was 

designed to achieve reductions of ten 

million tons of annual SO2 emissions, 

and, in combination with other 

provisions of the CAA, two million tons 

of annual NOX emissions.158

The SO2 cap-and-trade program was 

implemented in two phases. The first 

phase, beginning in 1995, targeted onehundred and ten named power plants, 

including specific generator units at 

each plant, requiring the plants to 

reduce their cumulative emissions to a 

specific level.159 Under certain 

conditions, the owner or operator of a 

named power plant could reassign an 

affected unit’s reduction requirement to 

another unit and/or request an 

extension of two years for meeting the 

requirement.160 Congress also 

established an energy conservation and 

RE reserve from which up to 300,000 

allowances could be allocated for 

qualified energy conservation measures 

or qualified RE.161

The second phase, beginning in 2000, 

expanded coverage to more than 2,000 

generating units and set a national cap 

at 8.90 million tons.162 Generally, 

allowances were allocated at a rate of 

1.2 lbs/mmBtu multiplied by the unit’s 

baseline and divided by 2000.163

However, bonus allowances could be 

awarded to certain units. 

Title IV also required the EPA to hold 

or sponsor annual auctions and sales of 

allowances for a small portion of the 

total allowances allocated each year. 

This ensured that some allowances 

would be directly available for new 

sources, including independent power 

production facilities.164

The provisions of the EPA’s Acid Rain 

Program are implemented through 

permits issued under the EPA’s Title V 

Operating Permit Program.165 In 

accordance with Title IV, moreover, 

each Title V permit application must 

include a compliance plan for the 

affected source that details how that 

source expects to meet the requirements 

of Title IV.166

2. Transport Rulemakings 

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

‘‘Good Neighbor Provision,’’ requires 

SIPs to prohibit emissions that 

‘‘contribute significantly to 

nonattainment . . . or interfere with 

maintenance’’ of the NAAQS in any 

other state.167 If the EPA finds that a 

state has failed to submit an approvable 

SIP, the EPA must issue a federal 

implementation plan (FIP) to prohibit 

those emissions ‘‘at any time’’ within 

the next two years.168

In three major rulemakings—the NOX

SIP Call,169 the Clean Air Interstate Rule 

(CAIR),170 and the Cross State Air 

Pollution Rule (CSAPR) 171—the EPA 

has attempted to delineate the scope of 

the Good Neighbor Provision. These 

rulemakings have several features in 

common. Although the Good Neighbor 

Provision does not speak specifically 

about EGUs, in all three rulemakings, 

the EPA set state emission ‘‘budgets’’ for 

upwind states based in part on 

emissions reductions achievable by 

EGUs through application of costeffective 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.172

The EPA determined that a uniform 

emission rate on large EGUs coupled 

with a cap-and-trade program was one 

such set of highly cost-effective 

controls.173 Accordingly, the EPA 

established an interstate cap-and-trade 

program—the NOX Budget Trading 

Program—as a mechanism for states to 

reduce emissions from EGUs and other 

sources in a highly cost-effective 

manner. The D.C. Circuit upheld the 

NOX SIP Call in most significant 

respects, including its use of costs to 

apportion emission reduction 

responsibilities.174

b. Clean Air Interstate Rule (CAIR). In 

2005, the EPA promulgated CAIR, 

which required 28 upwind states to 

reduce emissions of NOX and SO2 that 

would impact downwind areas with 

projected nonattainment and 

maintenance problems for ozone and 

PM2.5. The EPA determined emission 

reduction requirements based on 

‘‘controls that are known to be highly 

cost effective for EGUs.’’ 175 The EPA 

established cap-and-trade programs for 

sources of NOX and SO2 in states that 

chose to participate in the trading 

programs via their SIPs and for states 

ultimately subject to a FIP.176 As 

relevant here, the D.C. Circuit remanded 

CAIR in North Carolina v. EPA due to 

in part the structure of its interstate 

trading provisions and the way in which 

EPA applied the cost-effective standard, 

but kept the rule in place while the EPA 

developed an acceptable substitute.177

c. Cross-state Air Pollution Rule 

(CSAPR). In 2011, the EPA promulgated 

CSAPR, which required 27 upwind 

states to reduce emissions of NOX and 

SO2 that would impact downwind areas 

with projected nonattainment and 


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178 76 FR at 48270. The EPA adopted this 

approach in part to comport with the D.C. Circuit’s 

opinion in North Carolina v. EPA remanding CAIR. 

Id. at 48270–71. 

179 76 FR at 48209–16. 

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

S. Ct. 1584 (2014). 

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

182New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 

2008). 

183 70 FR 28606, at 28617. The EPA’s projections 

under CAIR showed a significant number of 

affected sources would install scrubbers for SO2 and 

selective catalytic reduction for NOX on coal-fired 

power plants, which had the co-benefit of capturing 

mercury emissions. Id. at 28619. 

184 70 FR 28606, at 28619. 

185 70 FR 28606, at 28620. 

186 70 FR 28606, at 28621. 

187 70 FR 28606, at 28621. That said, states could 

‘‘require reductions beyond those required by the 

[s]tate budget.’’ Id. at 28621. 

188 42 U.S.C. 7491(a)(1). 

189 42 U.S.C. 7491(b)(2). 

maintenance problems for ozone and 

PM2.5. The EPA determined emission 

reduction requirements based in part on 

the reductions achievable at certain cost 

thresholds by EGUs in each state, with 

certain provisions developed to account 

for the need to ensure reliability of the 

electric generating system.178 In the 

same action establishing these emission 

reduction requirements, the EPA 

promulgated FIPs that subjected states 

to trading programs developed to 

achieve the necessary reductions within 

each state.179 The U.S. Supreme Court 

upheld the EPA’s use of cost to set 

emission reduction requirements, as 

well as its authority to issue the FIPs.180

3. Clean Air Mercury Rule 

On March 15, 2005, the EPA issued a 

rule to control mercury (Hg) emissions 

from new and existing fossil fuel-fired 

power plants under CAA section 111(b) 

and (d). The rule, known as the Clean 

Air Mercury Rule (CAMR), established, 

in relevant part, a nationwide cap-andtrade program under CAA section 

111(d), which was designed to 

complement the cap-and-trade program 

for SO2 and NOX emissions under the 

Clean Air Interstate Rule (CAIR), 

discussed above.181 Though CAMR was 

later vacated by the D.C. Circuit on 

account of the EPA’s flawed CAA 

section 112 delisting rule, the court 

declined to reach the merits of the 

EPA’s interpretation of CAA section 

111(d).182 Accordingly, CAMR 

continues to be an informative model 

for a cap-and-trade program under CAA 

section 111(d). 

The cap-and-trade program in CAMR 

was designed to take effect in two 

phases: in 2010, the cap was set at 38 

tons of mercury per year, and in 2018, 

the cap would be lowered to 15 tons per 

year. The Phase I cap was set at a level 

reflecting the co-benefits of CAIR as 

determined through economic and 

environmental modeling.183 For the 

more stringent Phase II cap, the EPA 

projected that sources would ‘‘install 

SCR [selective catalytic reduction] to 

meet their SO2 and NOX requirements 

and take additional steps to address the 

remaining Hg reduction requirements 

under CAA section 111, including 

adding Hg-specific control technologies 

(model applies ACI [activated carbon 

injection]), additional scrubbers and 

SCR, dispatch changes, and coal 

switching.’’ 184 Based on this analysis, 

EPA determined that the BSER ‘‘refers 

to the combination of the cap-and-trade 

mechanism and the technology needed 

to achieve the chosen cap level.’’ 185

To accompany the nationwide 

emissions cap, the EPA also assigned a 

statewide emissions budget for mercury. 

Pursuant to CAA section 111(d), states 

would be required to submit plans to 

the EPA ‘‘detailing the controls that will 

be implemented to meet its specified 

budget for reductions from coal-fired 

Utility Units.’’ 186 Of course, states were 

‘‘not required to adopt and implement’’ 

the emission trading program, ‘‘but they 

[were] required to be in compliance 

with their statewide Hg emission 

budget.’’ 187

4. Mercury Air Toxics Rule 

On February 16, 2012, the EPA issued 

the MATS rule (77 FR 9304) to reduce 

emissions of toxic air pollutants from 

new and existing coal- and oil-fired 

EGUs. The MATS rule will reduce 

emissions of heavy metals, including 

mercury, arsenic, chromium, and nickel; 

and acid gases, including hydrochloric 

acid and hydrofluoric acid. These toxic 

air pollutants, also known as hazardous 

air pollutants or air toxics, are known to 

cause, or suspected of causing, nervous 

system damage, cancer, and other 

serious health effects. The MATS rule 

will also reduce SO2 and fine particle 

pollution, which will reduce particle 

concentrations in the air and prevent 

thousands of premature deaths and tens 

of thousands of heart attacks, bronchitis 

cases and asthma episodes. 

New or reconstructed EGUs (i.e., 

sources that commence construction or 

reconstruction after May 3, 2011) 

subject to the 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 reliabilitycritical units to receive an 

administrative order that includes a 

compliance schedule of up to an 

additional year, if it is needed to ensure 

electricity reliability. 

Following promulgation of the MATS 

rule, industry, states and environmental 

organizations challenged many aspects 

of the EPA’s threshold determination 

that regulation of EGUs is ‘‘appropriate 

and necessary’’ and the final standards 

regulating hazardous air pollutants from 

EGUs. The U.S. Court of Appeals for the 

D.C. Circuit upheld all aspects of the 

MATS rule. White Stallion Energy 

Center v. EPA, 748 F.3d 1222 (D.C. Cir. 

2014). In Michigan v. EPA, case no. 14– 

46, the U.S. Supreme Court reversed the 

portion of the D.C. Circuit decision 

finding the EPA was not required to 

consider cost when determining 

whether regulation of EGUs was 

‘‘appropriate’’ pursuant to section 

112(n)(1). The Supreme Court 

considered only the narrow question of 

whether the EPA erred in not 

considering cost when making this 

threshold determination. The Court’s 

decision did not disturb any of the other 

holdings of the D.C. Circuit. The Court 

remanded the case to the D.C. Circuit for 

further proceedings, and the MATS rule 

remains in place at this time. 

5. Regional Haze Rule 

Under CAA section 169A, Congress 

‘‘declare[d] as a national goal the 

prevention of any future, and the 

remedying of any existing, impairment 

of visibility’’ in national parks and 

wilderness areas that results from 

anthropogenic emissions.188 To achieve 

this goal, Congress directed the EPA to 

promulgate regulations directing states 

to submit SIPs that ‘‘contain such 

emission limits, schedules of 

compliance and other measures as may 

be necessary to make reasonable 

progress toward meeting the national 

goal. . . .’’ 189 One such measure that 

Congress deemed necessary to make 

reasonable progress was a requirement 

that certain older stationary sources that 

cause or contribute to visibility 

impairment ‘‘procure, install, and 

operate, as expeditiously as practicable 


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190 42 U.S.C. 7491(b)(2)(A). 

191 42 U.S.C. 7491(b)(2). 

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

193 64 FR 35714 (July 1, 1999) (codified at 40 CFR 

51.308–309). 

194 40 CFR 51.308(e)(1) & (2). 

195See Utility Air Regulatory Grp. v. EPA, 471 

F.3d 1333 (D.C. Cir. 2006); Ctr. for Econ. Dev. v. 

EPA, 398 F.3d 653 (D.C. Cir. 2005); Cent. Ariz. 

Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 1993). 

196 70 FR 39104 (July 6, 2005) (codified at 40 CFR 

pt. 51, app. Y). 

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

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

199The following discussion is not meant to be 

exhaustive. There are many other instances outside 

the context of the CAA, before and after 1970, when 

Congress discussed or was presented with evidence 

on climate change. 

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

1970), 1970 CAA Legis. Hist. at 349. 

201Council 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 2° to 3° F ‘‘could in a period 

of decades, lead to the start of substantial melting 

of ice caps and flooding of coastal regions.’’). 

202Council on Environmental Quality, ‘‘The First 

Annual Report of the Council on Environmental 

Quality,’’ p. 93–104 (Aug. 1970) 

203Testimony 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. 

204Testimony 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. 

205Testimony 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. 

206For instance, while scientists, such as Stephen 

Schneider of the National Center for Atmospheric 

Research, testified that ‘‘manmade pollutants will 

affect the climate,’’ they believed that we would 

‘‘see a general cooling of the Earth’s atmosphere.’’ 

Rep. Scheuer, H. Debates on H.R. 10498 (Sept. 15, 

1976), 1977 CAA Legis. Hist. at 6477. Additionally, 

the Department of Transportation’s climatic impact 

assessment program and the Climatic Impact 

Committee of the National Research Council, 

National Academies of Science and Engineering 

both reported that ‘‘warming or cooling’’ could 

occur. Id. at 6476. See also Sen. Bumpers, S. 

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

Legis. Hist. at 5368 (inserting ‘‘Summary of 

Statements Received [in the Subcommittee on the 

Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of 

Chronic Pollution’’ into the record, which noted 

that ‘‘there is near unamity [sic] that carbon dioxide 

concentrations in the atmosphere are increasing 

rapidly.’’). 

207 ‘‘Clean Air Act Amendments of 1977,’’ § 125, 

91 Stat. at 728. 

208Peterson, Thomas C., William M. Connolley, 

and John Fleck, ‘‘The Myth of the 1970s Global 

Cooling Scientific Consensus,’’ Bulletin of the 

American Meteorological Society, p. 1326 

(September 2008), available at http://

journals.ametsoc.org/doi/pdf/10.1175/

2008BAMS2370.1. 

. . . the best available retrofit 

technology,’’ more commonly referred 

to as BART.190 When determining BART 

for large fossil-fuel fired utility power 

plants, Congress required states to 

adhere to guidelines to be promulgated 

by the EPA.191 As with other SIP-based 

programs, the EPA is required to issue 

a FIP within two years if a state fails to 

submit a regional haze SIP or if the EPA 

disapproves such SIP in whole or in 

part.192

In 1999, the EPA promulgated the 

Regional Haze Rule to satisfy Congress’ 

mandate that EPA promulgate 

regulations directing states to address 

visibility impairment.193 Among other 

things, the Regional Haze Rule allows 

states to satisfy the Act’s BART 

requirement either by adopting sourcespecific emission limitations or by 

adopting alternatives, such as 

emissions-trading programs, that 

achieve greater reasonable progress than 

would source-specific BART.194 The 

Ninth Circuit and D.C. Circuit have both 

upheld the EPA’s interpretation that 

CAA section 169A(b)(2) allows for 

BART alternatives in lieu of sourcespecific BART.195 In 2005, the EPA 

promulgated BART Guidelines to assist 

states in determining which sources are 

subject to BART and what emission 

limitations to impose at those 

sources.196

The Regional Haze Rule set a goal of 

achieving natural visibility conditions 

by 2064 and requires states to revise 

their regional haze SIPs every ten 

years.197 The first planning period, 

which ends in 2018, focused heavily on 

the BART requirement. States (or the 

EPA in the case of FIPs) made numerous 

source-specific BART determinations, 

and developed several BART 

alternatives, for utility power plants. For 

the next planning period, states will 

need to determine whether additional 

controls are necessary at these plants 

(and others that were not subject to 

BART) in order to make reasonable 

progress towards the national visibility 

goal.198

F. Congressional Awareness of Climate 

Change in the Context of the Clean Air 

Act Amendments 199

During its deliberations on the 1970 

Clean Air Act Amendments, Congress 

learned that ongoing pollution, 

including from manmade carbon 

dioxide, could ‘‘threaten irreversible 

atmospheric and climatic changes.’’ 200

At that time, Congress heard the views 

of scientists that carbon dioxide 

emissions tended to increase global 

temperatures, but that there was 

uncertainty as to the extent to which 

those increases would be offset by the 

decreases in temperatures brought about 

by emissions of particulates. President 

Nixon’s Council on Environmental 

Quality (CEQ) reported that ‘‘the 

addition of particulates and carbon 

dioxide in the atmosphere could have 

dramatic and long-term effects on world 

climate.’’ 201 The CEQ’s First Annual 

Report, which was transmitted to 

Congress, devoted a chapter to ‘‘Man’s 

Inadvertent Modification of Weather 

and Climate.’’ 202 Moreover, Charles 

Johnson, Jr., Administrator of the 

Consumer Protection and 

Environmental Health Service, testified 

before the House Subcommittee on 

Public Health that ‘‘the carbon dioxide 

balance might result in the heating up 

of the atmosphere whereas the 

reduction of the radiant energy through 

particulate matter released to the 

atmosphere might cause reduction in 

radiation that reaches the earth.’’ 203

Administrator Johnson explained that 

the Nixon Administration was 

‘‘concerned . . . that neither of these 

things happen’’ and that they were 

‘‘watching carefully the kind of 

prognosis, the kind of calculations that 

the scientists make to look at the 

continuous balance between heat and 

cooling of the total earth’s 

atmosphere.’’ 204 He concluded that 

‘‘[w]hat we are trying to do, however, in 

terms of our air pollution effort should 

have a very salutary effect on either of 

these.’’ 205

Scientific reports on climatic change 

continued to gain traction in Congress 

through the mid-1970s, including while 

Congress was considering the 1977 CAA 

Amendments. However, uncertainty 

continued as to whether the increased 

warming brought about by carbon 

dioxide emissions would be offset by 

cooling brought about by particulate 

emissions.206 Congress ordered, as part 

of the 1977 CAA Amendments, the 

National Oceanic and Atmospheric 

Administration to research and monitor 

the stratosphere ‘‘for the purpose of 

early detection of changes in the 

stratosphere and climatic effects of such 

changes.’’ 207

Between the 1977 and 1990 Clean Air 

Act Amendments, scientific uncertainty 

yielded to the predominant view that 

global warming ‘‘was likely to dominate 

on time scales that would be significant 

to human societies.’’ 208 In fact, as part 

of the 1990 Clean Air Act Amendments, 

Congress specifically required the EPA 

to collect data on carbon dioxide 

emissions—the most significant of the 

GHGs—from all sources subject to the 


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209 ‘‘Clean Air Act Amendments of 1990,’’ § 820, 

104 Stat. at 2699. 

210Sen. Chafee, S. Debate on S. 1630 (Jan. 24, 

1990), 1990 CAA Legis. Hist. at 8662. 

211Additional Views of Rep. Markey and Rep. 

Moorhead, H.R. Rep. No. 101–490, at 674 (May 17, 

1990). 

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

213Article 2, Objective, The ultimate objective of 

this Convention and any related legal instruments 

that the Conference of the Parties may adopt is to 

achieve, in accordance with the relevant provisions 

of the Convention, stabilization of greenhouse gas 

concentrations in the atmosphere at a level that 

would prevent dangerous anthropogenic 

interference with the climate system. Such a level 

should be achieved within a time frame sufficient 

to allow ecosystems to adapt naturally to climate 

change, to ensure that food production is not 

threatened and to enable economic development to 

proceed in a sustainable manner. http://unfccc.int/ 

files/essential_background/convention/background/

application/pdf/convention_text_with_annexes_

english_for_posting.pdf 

214United States Cover Note to Intended 

Nationally Determined Contribution (INDC). 

Available online at: http://www4.unfccc.int/

submissions/INDC/Published%20Documents/

United%20States%20of%20America/1/

U.S.%20Cover%20Note%20INDC%

20and%20Accompanying%20Information.pdf. 

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

2830.php. 

216http://ec.europa.eu/clima/policies/brief/eu/

index_en.htm. 

217http://www.nature.com/news/stoppingdeforestation-battle-for-the-amazon-1.17223. 

218President Obama stated, in announcing the 

Climate Action Plan: 

‘‘The actions I’ve announced today should send 

a strong signal to the world that America intends 

to take bold action to reduce carbon pollution. We 

will continue to lead by the power of our example, 

because that’s what the United States of America 

has always done.’’ President Obama, Climate Action 

Plan speech, Georgetown University, 2013. 

Available at https://www.whitehouse.gov/the-pressoffice/2013/06/25/remarks-president-climatechange. 

newly enacted operating permit 

program under Title V.209 Although 

Congress did not require the EPA to take 

immediate action to address climate 

change, Congress did identify certain 

tools that were particularly helpful in 

addressing climate change in the utility 

power sector. The Senate report 

discussing the acid rain provisions of 

Title IV noted that some of the measures 

that would reduce coal-fired power 

plant emissions of the precursors to acid 

rain would also reduce those facilities’ 

emissions of CO2. The report stated: 

Energy efficiency is a crucial tool for 

controlling the emissions of carbon dioxide, 

the gas chiefly responsible for the 

intensification of the atmospheric 

‘greenhouse effect.’ In the last several years, 

the Committee has received extensive 

scientific testimony that increases in the 

human-caused emissions of carbon dioxide 

and other greenhouse gases will lead to 

catastrophic shocks in the global climate 

system. Accordingly, new title IV shapes an 

acid rain reduction policy that encourages 

energy efficiency and other policies aimed at 

controlling greenhouse gases.210

Similarly, Title IV provisions to 

encourage RE were justified because 

‘‘renewables not only significantly 

curtail sulfur dioxide emissions, but 

they emit little or no nitrogen oxides 

and carbon dioxide’’.211

G. International Agreements and 

Actions 

In this final rule, the U.S. is taking 

action to limit GHGs from one of its 

largest emission sources. Climate 

change is a global problem, and the U.S. 

is not alone in taking action to address 

it. The UNFCCC 212 is the international 

treaty under which countries (called 

‘‘Parties’’) cooperatively consider what 

can be done to limit anthropogenic 

climate change 213 and adapt to climate 

change impacts. Currently, there are 195 

Parties to the UNFCCC, including the 

U.S. The Conference of the Parties 

(COP) meets annually and is currently 

considering commitments countries can 

make to limit emissions after 2020. The 

2015 COP will be in Paris and is 

expected to represent an historic step 

for climate change mitigation. The 

Parties to the UNFCC will meet to 

establish a climate agreement that 

applies to all countries and focuses on 

reducing GHG emissions. Such an 

outcome would send a beneficial signal 

to the markets and civil society about 

global action to address climate change. 

Many countries have announced their 

intended post-2020 commitments 

already, and other countries are 

expected to do so before December. In 

April 2015, the U.S. announced its 

commitment to reduce GHG emissions 

26–28 percent below 2005 levels by 

2025.214

As Parties to both the UNFCCC and 

the Kyoto Protocol,215 the European 

Union (EU) and member countries have 

taken aggressive action to reduce GHG 

emissions.216 EU initiatives to reduce 

GHG emissions include the EU 

Emissions Trading System, legislation to 

increase the adoption of RE sources, 

strengthened EE targets, vehicle 

emission standards, and support for the 

development of CCS technology for use 

by the power sector and other industrial 

sources. In 2009, the EU announced its 

‘‘20–20–20 targets,’’ including a 20 

percent reduction in GHG emissions 

from 1990 levels by 2020, an increase of 

20 percent in the share of energy 

consumption produced by renewable 

resources, and a 20 percent 

improvement in EE. In March 2015, the 

EU announced its commitment to 

reduce domestic GHG emissions by at 

least 40% from 1990 levels by 2030. 

Recently, China has also agreed to 

take action to address climate change. In 

November 2014, in a joint 

announcement by President Obama and 

China’s President Xi, China pledged to 

curtail GHG emissions, with emissions 

peaking in 2030 and then declining 

thereafter, and to increase the share of 

energy from non-carbon sources (solar, 

wind, hydropower, nuclear) to 20 

percent by 2030. 

Mexico is committed to reduce 

unconditionally 25 percent of its 

emissions of GHGs and short-lived 

climate pollutants (below business as 

usual) for the year 2030. This 

commitment implies a 22 percent 

reduction of GHG emissions and a 51 

percent reduction of black carbon 

emissions. 

Brazil has reduced its net CO2

emissions more than any other country 

through a historic effort to slow forest 

loss. The deforestation rate in Brazil in 

2014 was roughly 75 percent below the 

average for 1996 to 2005.217

Together, countries that have already 

announced their intended post-2020 

commitments, including the U.S., 

China, European Union, Mexico, 

Russian Federation and Brazil, make up 

a large majority of global emissions. 

President Obama’s Climate Action 

Plan contains a number of policies and 

programs that are intended to cut carbon 

pollution that causes climate change 

and affects public health. The Clean 

Power Plan is a key component of the 

plan, addressing the nation’s largest 

source of emissions in a comprehensive 

manner. Collectively, these policies will 

help spark business innovation, result 

in cleaner forms of energy, create jobs, 

and cut dependence on foreign oil. They 

also demonstrate to the rest of the world 

that the U.S. is contributing its share of 

the global effort that is needed to 

address climate change.218 This 

demonstration encourages other major 

economies to take on similar 

contributions, which is critical given the 

global impact of GHG emissions. The 

State Department Special Envoy for 

Climate Change Todd Stern, the lead 

U.S. climate change negotiator, noted 

the connection between domestic and 

international action to address climate 

change in his speech at Yale University 

on October 14, 2014: 

This mobilization of American effort 

matters. Enormously. It matters because the 

United States is the biggest economy and 

largest historic emitter of greenhouse gases. 

Because, here, as in so many areas, we feel 

a responsibility to lead. And because here, as 

in so many areas, we find that American 

commitment is indispensable to effective 

international action. 

And make no mistake—other countries see 

what we are doing and are taking note. As 

I travel the world and meet with my 


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

1970), 1970 CAA Legis. Hist. at 224. 

220Sen. Muskie, S. Consideration of H.R. Conf. 

Rep. No. 91–1783 (Dec. 18, 1970), 1970 CAA Legis. 

Hist.pa at 123. 

221Sen. 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. 

222Sen. Muskie, S. Consideration of H.R. Conf. 

Rep. No. 91–1783 (Dec. 18, 1970), 1970 CAA Legis. 

Hist. at 123. 

223 ‘‘Clean Air Act Amendments of 1970,’’ Pub. L. 

91–604, § 4, 84 Stat. 1676, 1678 (Dec. 31, 1970). The 

‘‘adverse effect’’ criterion was later amended to 

refer to pollutants ‘‘which may reasonably be 

anticipated to endanger public health or welfare’’. 

See 42 U.S.C. 7408(a)(1)(A). Similar language is also 

used under the current CAA section 111. See 42 

U.S.C. 7411(b)(1)(A). 

224 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1680. 

225 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1684. 

226 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1685. 

227 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1685. 

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

229H.R. Rep. No. 95–294, at 194 (May 12, 1977). 

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

231 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1683. 

232 ‘‘Clean Air Act Amendments of 1990,’’ Pub. L. 

101–549, § 403, 104 Stat. 2399, 2631 (Nov. 15, 1990) 

(retaining only the obligation to account for ‘‘any 

nonair quality health and environmental impact 

and energy requirements’’ that was added in 1977). 

233As 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). 

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

counterparts, the palpable engagement of 

President Obama and his team has put us in 

a stronger, more credible position than ever 

before. 

This final rule demonstrates to other 

countries that the U.S. is taking action 

to limit GHG emissions from its largest 

emission sources, in line with our 

international commitments. The impact 

of GHGs is global, and U.S. action to 

reduce GHG emissions complements 

and encourages ongoing programs and 

efforts in other countries. 

H. Legislative and Regulatory 

Background for CAA Section 111 

In the final days of December 1970, 

Congress enacted sweeping changes to 

the Air Quality Act of 1967 to confront 

an ‘‘environmental crisis.’’ 219 The Air 

Quality Act—which expanded federal 

air pollution control efforts after the 

enactment of the Clean Air Act of 

1963—prioritized the adoption of 

ambient air standards but failed to target 

stationary sources of air pollution. As a 

result, ‘‘[c]ities up and down the east 

coast were living under clouds of smoke 

and daily air pollution alerts.’’ 220 In 

fact, ‘‘[o]ver 200 million tons of 

contaminants . . . spilled into the air’’ 

each year.221 The 1970 CAA 

Amendments were designed to face this 

crisis ‘‘with urgency and in candor.’’ 222

For the most part, Congress gave EPA 

and the states flexible tools to 

implement the CAA. This is best 

exhibited by the newly enacted 

programs regulating stationary sources. 

For these sources, Congress crafted a 

three-legged regime upon which the 

regulation of stationary sources was 

intended to sit. 

The first prong—CAA sections 107– 

110—addressed what are commonly 

referred to as criteria pollutants, ‘‘the 

presence of which in the ambient air 

results from numerous or diverse mobile 

or stationary sources’’ and are 

determined to have ‘‘an adverse effect 

on public health or welfare’’.223 Under 

these provisions, states would have the 

primary responsibility for assuring air 

quality within their entire geographic 

area but would submit plans to the 

Administrator for ‘‘implementation, 

maintenance, and enforcement’’ of 

national ambient air quality standards. 

These plans would include ‘‘emission 

limitations, schedules, and timetables 

for compliance . . . and such other 

measures as may be necessary to insure 

attainment and maintenance’’ of the 

national ambient air quality 

standards.224

The second prong—CAA section 

111—addressed pollutants on a source 

category-wide basis. Under CAA section 

111(b), the EPA lists source categories 

which ‘‘contribute significantly to air 

pollution which causes or contributes to 

the endangerment of public health or 

welfare,’’ And then establishes 

‘‘standards of performance’’ for the new 

sources in the listed category.225 For 

existing sources in a listed source 

category, CAA section 111(d) set out 

procedures for the establishment of 

federally enforceable ‘‘emission 

standards’’ of any pollutant not 

otherwise controlled under the CAA’s 

SIP provisions or CAA section 112. 

Lastly, the third prong—CAA section 

112—addressed hazardous air 

pollutants through the establishment of 

national ‘‘emission standards’’ at a level 

which ‘‘provides an ample margin of 

safety to protect the public health’’.226

All new or modified sources of any 

hazardous air pollutant would be 

required to meet these emission 

standards. Existing sources were 

required to meet the same standards or 

would be shut down unless they 

obtained a temporary EPA waiver or 

Presidential exemption.227

At its inception, CAA section 111 was 

intended to bear a significant weight 

under this three-legged regime. Indeed, 

by 1977, the EPA had promulgated six 

times as many performance standards 

under CAA section 111 than emission 

standards under CAA section 112.228

That said, states, including Texas and 

New Jersey, levied ‘‘substantial 

criticisms’’ against the EPA for not 

moving rapidly enough.229 Accordingly, 

the 1977 CAA Amendments were 

designed to ‘‘provide a greater role for 

the [s]tates in standards setting under 

the [CAA],’’ ‘‘protect [s]tates from 

‘environmental blackmail’ as they 

attempt to regulate mobile and 

competitive industries,’’ and lastly 

‘‘provide a check on the Administrator’s 

inaction or failure to control emissions 

adequately.’’ 230

At bottom, CAA section 111 rests on 

the definition of a standard of 

performance under CAA section 

111(a)(1), which reads nearly the same 

now as it did when it was first adopted 

in the 1970 CAA Amendments. In 1970, 

Congress defined standard of 

performance—a term which had not 

previously appeared in the CAA—as 

a standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction) the Administrator 

determines has been adequately 

demonstrated.231

Despite significant changes to this 

definition in 1977, Congress reversed 

course in 1990 and largely reinstated the 

original definition.232 As presently 

defined, the term applies to the 

regulation of new and existing sources 

under CAA sections 111(b) and (d).233

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 non-hazardous pollutants] 

to the fullest extent compatible with the 

available technology and economic 

feasibility.’’ 234 The House also 


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235H.R. 17255, 91st Cong. § 5 (1970). 

236S. 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). 

237S. 4358, 91st Cong. § 6 (1970). 

238The House bill did not provide for the direct 

regulation of existing sources. 

239See S. Rep. No. 91–1196, at 18 and 20 (Sept. 

17, 1970). 

240S. 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). 

241See ‘‘Clean Air Act Amendments of 1970,’’ 

§ 12, 84 Stat. at 1706. 

242 ‘‘Clean Air Act Amendments of 1970,’’ § 4, 84 

Stat. at 1679. 

243 ‘‘Standards of Performance for New Stationary 

Sources: Proposed Standards for Five Categories,’’ 

36 FR 15704 (Aug. 17, 1971). See ‘‘Clean Air Act 

Amendments of 1970,’’ § 4, 84 Stat. at 1684 

(requiring the Administrator to publish a list of 

categories of stationary sources within 90 days of 

the enactment of the 1970 CAA Amendments). 

244 36 FR at 15704–706; and ‘‘Standards of 

Performance for New Stationary Sources,’’ 36 FR 

24876, 24879 (Dec. 23, 1971). 

245See ‘‘State Plans for the Control of Existing 

Facilities,’’ 39 FR 36102 (Oct. 7, 1974). 

246See ‘‘State Plans for the Control of Certain 

Pollutants from Existing Facilities,’’ 40 FR 53340 

(Nov. 17, 1975). 

247See ‘‘Phosphate Fertilizer Plants; Draft 

Guideline Document; Availability,’’ 41 FR 19585 

(May 12, 1976); and ‘‘Phosphate Fertilizer Plants; 

Final Guideline Document Availability,’’ 42 FR 

12022 (Mar. 1, 1977). 

248For example, Congress recognized that many 

air pollutants had not been regulated despite 

‘‘mounting evidence’’ that these pollutants ‘‘are 

associated with serious health hazards’’. H.R. Rep. 

No. 94–1175, 22 (May, 15, 1976). Because EPA 

‘‘failed to promulgate regulations to institute 

adequate control measures,’’ Congress ordered EPA 

to regulate four specific pollutants that had ‘‘been 

found to be cancer-causing or cancer-promoting’’. 

Id. at 23. This directive, reflected in CAA section 

122, specifically added radioactive pollutants, 

cadmium, arsenic, and polycyclic organic matter 

‘‘under the various provisions of the Clean Air Act 

and allows their regulation as criteria pollutants 

under ambient air quality standards, as hazardous 

air pollutants, or under new source performance 

standards, as appropriate.’’ H.R. Conf. Rep. No. 95– 

564, 142 (Aug. 3, 1977), 1977 CAA Legis. Hist. at 

522. At the same time, Congress made sure that 

these commands would have no effect on the 

Administrator’s discretion to address ‘‘any 

substance (whether or not enumerated [under CAA 

section 122(a))’’ under CAA sections 108, 112, or 

111. 42 U.S.C. 7422(b). 

249See 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. 

250See ‘‘Clean Air Act Amendments of 1977,’’ 

Pub. L. 95–95, §§ 127–129, 91 Stat. 685 (Aug. 7, 

1977). 

251 ‘‘Clean Air Act Amendments of 1977,’’ § 109, 

91 Stat. at 697. 

proposed to prohibit the construction or 

operation of new sources of ‘‘extremely 

hazardous’’ pollutants.235 The Senate 

bill, on the other hand, authorized 

‘‘Federal standards of performance,’’ 

which would ‘‘reflect the greatest degree 

of emission control which the Secretary 

[later, the Administrator] determines to 

be achievable through application of the 

latest available control technology, 

processes, operating methods, or other 

alternatives.’’ 236 The Senate also would 

have authorized ‘‘national emission 

standards’’ for hazardous air pollution 

and other ‘‘selected air pollution 

agents.’’ 237

After conference, CAA section 111 

emerged as one of the CAA’s three 

programs for regulating stationary 

sources. In defining the newly formed 

‘‘standards of performance,’’ Congress 

appeared to merge the various ‘‘means 

of preventing and controlling air 

pollution’’ under the Senate bill with 

the consideration of costs that was 

central to the House bill into the BSER. 

At the time, however, this definition 

only applied to new sources under CAA 

section 111(b). 

To regulate existing sources, Congress 

collapsed section 114 of the Senate bill 

into CAA section 111(d).238 Section 114 

of the Senate bill established emission 

standards for ‘‘selected air pollution 

agents,’’ and was intended to bridge the 

gap between criteria pollutants and 

hazardous air pollutants. As proposed, 

the Senate identified fourteen 

substances for regulation under section 

114 and only four substances for 

regulation under Senate bill 4358, 

section 115, the predecessor of CAA 

section 112.239

As adopted, CAA section 111(d) 

requires states to submit plans to the 

Administrator establishing ‘‘emission 

standards’’ for certain existing sources 

of air pollutants that were not otherwise 

regulated as criteria pollutants or 

hazardous air pollutants. This ensured 

that there would be ‘‘no gaps in control 

activities pertaining to stationary source 

emissions that pose any significant 

danger to public health or welfare.’’ 240

The term ‘‘emission standards,’’ 

however, was not expressly defined in 

the 1970 CAA Amendments (save for 

purposes of citizen suit enforcement) 

even though the term was also used 

under the CAA’s SIP provisions and 

CAA section 112.241 That said, under 

the newly enacted ‘‘ambient air quality 

and emission standards’’ sections, 

Congress directed the EPA to provide 

states with information ‘‘on air 

pollution control techniques,’’ including 

data on ‘‘available technology and 

alternative methods of prevention and 

control of air pollution’’ and on 

‘‘alternative fuels, processes, and 

operating methods which will result in 

elimination or significant reduction of 

emissions.’’ 242 Similarly, the 

Administrator would ‘‘issue information 

on pollution control techniques for air 

pollutants’’ in conjunction with 

establishing emission standards under 

CAA section 112. However, analogous 

text is absent from CAA section 111(d). 

After the enactment of the 1970 CAA 

Amendments, the EPA proposed 

standards of performance for an ‘‘initial 

list of five stationary source categories 

which contribute significantly to air 

pollution’’ in August 1971.243 The first 

category listed was for fossil-fuel fired 

steam generators, for which EPA 

proposed and promulgated standards for 

particulate matter, SO2, and NOX.244

Several years later, the EPA proposed 

its implementing regulations for CAA 

section 111(d).245 These regulations 

were finalized in November 1975, and 

provided for the publication of emission 

guidelines.246 The first emission 

guidelines were proposed in May 1976 

and finalized in March 1977.247

Despite these first steps taken under 

CAA sections 111(b) and (d), Congress 

revisited the CAA in 1977 to address 

growing concerns with the nation’s 

response to the 1973 oil embargo (noted 

above), to respond to new 

environmental problems such as 

stratospheric ozone depletion, and to 

resolve other issues associated with 

implementing the 1970 CAA 

Amendments.248 Most notably, an 

increase in coal use as a result of the oil 

crisis meant that ‘‘vigorous and effective 

control’’ of air emissions was ‘‘even 

more urgent.’’ 249 Thus, to curb the 

projected surge in air emissions, 

Congress enacted several new 

provisions to the CAA. These new 

provisions include the prevention of 

significant deterioration (PSD) program, 

visibility protections, and requirements 

for nonattainment areas.250

Congress also made significant 

changes to CAA section 111. For 

example, Congress amended the 

definition of a standard of performance 

(including by requiring the 

consideration of ‘‘nonair quality health 

and environmental impact and energy 

requirements’’), authorized alternative 

(e.g., work practice or design) standards 

in limited circumstances, provided 

states with authority to petition the 

Administrator for new or revised (and 

more stringent) standards, and imposed 

a strict regulatory schedule for 

establishing standards of performance 

for categories of major stationary 

sources that had not yet been listed.251


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252H.R. Rep. No. 95–294, at 192 (May 12, 1977). 

Congress separately defined ‘‘technological system 

of continuous emission reduction’’ as ‘‘(A) a 

technological process for production or operation 

by any source which is inherently low-polluting or 

nonpolluting, or (B) technological system for 

continuous reduction of the pollution generated by 

a source before such pollution is emitted into the 

ambient air, including precombustion cleaning or 

treatment of fuels.’’ ‘‘Clean Air Act Amendments of 

1977,’’ § 109, 91 Stat. at 700; see also 42 U.S.C. 

7411(a)(7). 

253 ‘‘Clean Air Act Amendments of 1977,’’ § 109, 

91 Stat. at 700. 

254 ‘‘New Stationary Sources Performance 

Standards; Electric Utility Steam Generating Units,’’ 

44 FR 33580, 33581–82 (June 11, 1979). 

255H.R. Rep. No. 95–294, at 195 (May 12, 1977). 

256Sen. Muskie, S. Consideration of the H.R. 

Conf. Rep. No. 95–564 (Aug. 4, 1977), 1977 CAA 

Legis. Hist. at 353. 

257This concept was already reflected in the 

EPA’s CAA section 111(d) implementing 

regulations under 40 CFR 60.24(f). See 40 FR 53340, 

53347 (Nov. 17, 1975). 

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

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

260Congress also updated the regulatory schedule 

that was added in the 1977 CAA Amendments to 

reflect the newly enacted 1990 CAA Amendments. 

See ‘‘Clean Air Act Amendments of 1990,’’ § 108, 

104 Stat. 2467. 261 ‘‘Clean Air Act Amendments of 1990,’’ § 403, 

104 Stat. at 2631. 262 ‘‘Clean Air Act Amendments of 1990,’’ § 301, 

104 Stat. at 2631. 263CAA section 111(b)(1)(A). 264See 40 CFR 60 subparts Cb—OOOO. 265CAA section 111(b)(1)(B), 111(a)(1). 

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

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

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.’ ’’ 252

For fossil-fuel fired stationary sources, 

Congress further required a percentage 

reduction in emissions from the use of 

fuels.253 Together, this was designed to 

‘‘force new sources to burn high-sulfur 

fuel thus freeing low-sulfur fuel for use 

in existing sources where it is harder to 

control emissions and where low-sulfur 

fuel is needed for compliance.’’ 254

Congress also clarified that with 

respect to CAA section 111(d), 

standards of performance (now 

applicable in lieu of emission standards) 

‘‘would be based on the best available 

means (not necessarily 

technological)’’.255 This was intended to 

distinguish existing source standards 

from new source standards, for which 

‘‘the requirement for [the BSER] has 

been more narrowly redefined as best 

technological system of continuous 

emission reduction.’’ 256 Additionally, 

Congress clarified that states could 

consider ‘‘the remaining useful life’’ of 

a source when applying a standard of 

performance to a particular existing 

source.257

In the twenty years since the 1970 

CAA Amendments and in spite of the 

refinements of the 1977 CAA 

Amendments, ‘‘many of the Nation’s 

most important air pollution problems 

[had] failed to improve or [had] grown 

more serious.’’ 258 Indeed, in 1989, 

President George Bush said that 

‘‘ ‘progress has not come quickly enough 

and much remains to be done.’ ’’ 259 This 

time, with the 1990 CAA Amendments, 

Congress substantially overhauled the 

CAA. In particular, Congress again 

added to the NAAQS program, 

completely revised CAA section 112, 

added a new title to target existing fossil 

fuel-fired stationary sources and address 

growing concerns with acid rain, 

imported an operating permit modeled 

off the Clean Water Act, and established 

a phase out of certain ozone depleting 

substances. 

All told, however, there was minimal 

debate on changes to CAA section 111. 

In fact, the only discussion centered on 

the repeal of the percentage reduction 

requirement, which became seen as 

unduly restrictive. Accordingly, 

Congress reverted the definition of 

‘‘standard of performance’’ to the 

definition agreed to in the 1970 CAA 

Amendments, but retained the 

requirement to consider nonair quality 

environmental impacts and energy 

requirements added in 1977.260

However, the repeal would only apply 

so long as the SO2 cap under CAA 

section 403(e) of the newly established 

acid rain program remained in effect.261

Lastly, Congress instructed the EPA to 

revise its new source performance 

standards for SO2 emissions from fossil 

fuel-fired power plants but required that 

the revised emission rate be no less 

stringent than before.262

I. Statutory and Regulatory 

Requirements 

Clean Air Act section 111, which 

Congress enacted as part of the 1970 

Clean Air Act Amendments, establishes 

mechanisms for controlling emissions of 

air pollutants from stationary sources. 

This provision requires the EPA to 

promulgate a list of categories of 

stationary sources that the 

Administrator, in his or her judgment, 

finds ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ 263 The EPA 

has listed more than 60 stationary 

source categories under this 

provision.264 Once the EPA lists a 

source category, the EPA must, under 

CAA section 111(b)(1)(B), establish 

‘‘standards of performance’’ for 

emissions of air pollutants from new 

sources in the source categories.265

These standards are known as new 

source performance standards (NSPS), 

and they are national requirements that 

apply directly to the sources subject to 

them. 

When the EPA establishes NSPS for 

new sources in a particular source 

category, the EPA is also required, 

under CAA section 111(d)(1), to 

prescribe regulations for states to submit 

plans regulating existing sources in that 

source category for any air pollutant 

that, in general, is not regulated under 

the CAA section 109 requirements for 

the NAAQS or regulated under the CAA 

section 112 requirements for HAP. CAA 

section 111(d)’s mechanism for 

regulating existing sources differs from 

the one that CAA section 111(b) 

provides for new sources because CAA 

section 111(d) contemplates states 

submitting plans that establish 

‘‘standards of performance’’ for the 

affected sources and that contain other 

measures to implement and enforce 

those standards. 

‘‘Standards of performance’’ are 

defined under CAA section 111(a)(1) as 

standards for emissions that reflect the 

emission limitation achievable from the 

‘‘best system of emission reduction,’’ 

considering costs and other factors, that 

‘‘the Administrator determines has been 

adequately demonstrated.’’ CAA section 

111(d)(1) grants states the authority, in 

applying a standard of performance to a 

particular source, to take into account 

the source’s remaining useful life or 

other factors. 

Under CAA section 111(d), a state 

must submit its plan to the EPA for 

approval, and the EPA must approve the 

state plan if it is ‘‘satisfactory.’’ 266 If a 

state does not submit a plan, or if the 

EPA does not approve a state’s plan, 

then the EPA must establish a plan for 

that state.267 Once a state receives the 

EPA’s approval of its plan, the 

provisions in the plan become federally 

enforceable against the entity 

responsible for noncompliance, in the 

same manner as the provisions of an 

approved SIP under the Act. 

Section 302(d) of the CAA defines the 

term ‘‘state’’ to include the 

Commonwealth of Puerto Rico, the 

Virgin Islands, Guam, American Samoa 

and the Commonwealth of the Northern 

Mariana Islands. While 40 CFR part 60 

contains a separate definition of ‘‘state’’ 

at section 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 


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268The 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. 

269 ‘‘State Plans for the Control of Certain 

Pollutants from Existing Facilities,’’ 40 FR 53340 

(Nov. 17, 1975). 270The most recent amendment was in 77 FR 

9304 (Feb. 16, 2012). 

271 40 CFR 60.22. In the 1975 rulemaking, the 

EPA explained that it used the term ‘‘emission 

guidelines’’—instead of emissions limitations—to 

make clear that guidelines would not be binding 

requirements applicable to the sources, but instead 

are ‘‘criteria for judging the adequacy of State 

plans.’’ 40 FR at 53343. 

272 40 CFR 60.23(a)(1). 

273 40 CFR 60.27(b). 

274See 40 CFR 60.27(a). 

275See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12022 

(Mar. 1, 1977); ‘‘Standards of Performance for New 

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

276See, e.g., ‘‘Standards of Performance for New 

Stationary Sources and Emission Guidelines for 

Existing Sources: Sewage Sludge Incineration Units, 

Final Rule,’’ 76 FR 15372 (Mar. 21, 2011). 

277See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12022 

(Mar. 1, 1977); ‘‘Standards of Performance for New 

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

‘‘all non-Federal authorities, including 

local agencies, interstate associations, 

and State-wide programs that have been 

delegated authority to implement: (1) 

The provisions of this part and/or (2) 

the permit program established under 

part 70 of this chapter. The term State 

shall have its conventional meaning 

where clear from the context.’’ The EPA 

believes that the last sentence refers to 

the conventional meaning of ‘‘state’’ 

under the CAA. Thus, the EPA believes 

the term ‘‘state’’ as used in the emission 

guidelines is most reasonably 

interpreted as including the meaning 

ascribed to that term in section 302(d) 

of the CAA, which expressly includes 

U.S. territories. 

Section 301(d)(A) of the CAA 

recognizes that the American Indian 

tribes are sovereign Nations and 

authorizes the EPA to ‘‘treat tribes as 

States under this Act’’. The Tribal 

Authority Rule (63 FR 7254, February 

12, 1998) identifies that EPA will treat 

tribes in a manner similar to states for 

all of the CAA provisions with the 

exception of, among other things, 

specific plan submittal and 

implementation deadlines under the 

CAA. As a result, though they operate 

as part of the interconnected system of 

electricity production and distribution, 

affected EGUs located in Indian country 

would not be encompassed within a 

state’s CAA section 111(d) plan. Instead, 

an Indian tribe with one or more 

affected EGUs located in its area of 

Indian country 268 will have the 

opportunity, but not the obligation, to 

apply for eligibility to develop and 

implement a CAA section 111(d) plan. 

The Indian tribe would need to be 

approved by the EPA as eligible to 

develop and implement a CAA section 

111(d) plan following the procedure set 

forth in 40 CFR part 49. Once a tribe is 

approved as eligible for that purpose, it 

would be treated in the same manner as 

a state, and references in the emission 

guidelines to states would refer equally 

to the tribe. The EPA notes that, while 

tribes have the opportunity to apply for 

eligibility to administer CAA programs, 

they are not required to do so. Further, 

the EPA has established procedures in 

40 CFR part 49 (see particularly 40 CFR 

49.7(c)) that permit eligible tribes to 

request approval of reasonably severable 

partial program elements. Those 

procedures are applicable here. 

In these final emission guidelines, the 

term ‘‘state’’ encompasses the 50 states 

and the District of Columbia, U.S. 

territories, and any Indian tribe that has 

been approved by the EPA pursuant to 

40 CFR 49.9 as to develop and 

implement a CAA section 111(d) plan. 

The EPA issued regulations 

implementing CAA section 111(d) in 

1975,269 and has revised them in the 

years since.270 (We refer to the 

regulations generally as the 

implementing regulations.) These 

regulations provide that, in 

promulgating requirements for sources 

under CAA section 111(d), the EPA first 

develops regulations known as 

‘‘emission guidelines,’’ which establish 

binding requirements that states must 

address when they develop their 

plans.271 The implementing regulations 

also establish timetables for state and 

EPA action: States must submit state 

plans within 9 months of the EPA’s 

issuance of the guidelines,272 and the 

EPA must take final action on the state 

plans within 4 months of the due date 

for those plans,273 although the EPA has 

authority to extend those deadlines.274

In this rulemaking, the EPA is following 

the requirements of the implementing 

regulations, and is not re-opening them, 

except that the EPA is extending the 

timetables, as described below. 

Over the last forty years, under CAA 

section 111(d), the agency has regulated 

four pollutants from five source 

categories (i.e., sulfuric acid plants (acid 

mist), phosphate fertilizer plants 

(fluorides), primary aluminum plants 

(fluorides), Kraft pulp plants (total 

reduced sulfur), and municipal solid 

waste landfills (landfill gases)).275 In 

addition, the agency has regulated 

additional pollutants under CAA 

section 111(d) in conjunction with CAA 

section 129.276 The agency has not 

previously regulated CO2 or any other 

GHGs under CAA section 111(d). 

The EPA’s previous CAA section 

111(d) actions were necessarily geared 

toward the pollutants and industries 

regulated. Similarly, in this rulemaking, 

in defining CAA section 111(d) 

emission guidelines for the states and 

determining the BSER, the EPA believes 

that taking into account the particular 

characteristics of carbon pollution, the 

interconnected nature of the power 

sector and the manner in which EGUs 

are currently operated is warranted. 

Specifically, the operators themselves 

treat increments of generation as 

interchangeable between and among 

sources in a way that creates options for 

relying on varying utilization levels, 

lowering carbon generation, and 

reducing demand as components of the 

overall method for reducing CO2

emissions. Doing so results in a broader, 

forward-thinking approach to the design 

of programs to yield critical CO2

reductions that improve the overall 

power system by lowering the carbon 

intensity of power generation, while 

offering continued reliability and costeffectiveness. These opportunities exist 

in the utility power sector in ways that 

were not relevant or available for other 

industries for which the EPA has 

established CAA section 111(d) 

emission guidelines.277

In this action, the EPA is 

promulgating emission guidelines for 

states to follow in developing their CAA 

section 111(d) plans to reduce emissions 

of CO2 from the utility power sector. 

J. Clean Power Plan Proposal and 

Supplemental Proposal 

On June 18, 2014, the EPA proposed 

emission guidelines for states to follow 

in developing plans to address GHG 

emissions from existing fossil fuel-fired 

electric generating units (EGUs). 

Specifically, the EPA proposed ratebased goals for CO2 emissions for each 


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278Presidential Memorandum—Power Sector 

Carbon Pollution Standards, June 25, 2013. http:// 

www.whitehouse.gov/the-press-office/2013/06/25/

presidential-memorandum-power-sector-carbonpollution-standards. 

279The EPA received more than 2,000 emails 

offering input into the development of these 

guidelines through email and a Web-based 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. 280Summaries of the 11 public listening sessions 

in 2013 are available at www.regulations.gov at EPA 

Docket ID No. EPA–HQ–OAR–2014–0020. 

state with existing fossil fuel-fired 

EGUs, as well as guidelines for plans to 

achieve those goals. On November 4, 

2014, the EPA published a 

supplemental proposal that proposed 

emission rate-based goals for CO2

emissions for U.S. territories and areas 

of Indian country with existing fossil 

fuel-fired EGUs. In the supplemental 

proposal, the EPA also solicited 

comment on authorizing jurisdictions 

(including any states, territories and 

areas of Indian country) without 

existing fossil fuel-fired EGUs subject to 

the proposed emission guidelines to 

partner with jurisdictions (including 

any states) that do have existing fossil 

fuel-fired EGUs subject to the proposed 

emission guidelines in developing 

multi-jurisdictional plans. The EPA also 

solicited comment on the treatment of 

RE, demand-side EE and other new lowor zero-emitting electricity generation 

across international boundaries in a 

state plan. 

The EPA also issued two documents 

after the June 18, 2014 proposal. On 

October 30, 2014, the EPA published a 

NODA in which the agency provided 

additional information on several topics 

raised by stakeholders and solicited 

comment on the information presented. 

This action covered three topic areas: 1) 

the emission reduction compliance 

trajectories created by the interim goal 

for 2020 to 2029, 2) certain aspects of 

the building block methodology, and 3) 

the way state-specific CO2 goals are 

calculated. 

In a separate action, the EPA 

published a document 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 action, 

the EPA also made available, in the 

docket for this rulemaking, a TSD that 

provided two examples of how a state, 

U.S. territory or tribe could translate a 

rate-based CO2 goal to total metric tons 

of CO2 (a mass-based equivalent). 

K. Stakeholder Outreach and 

Consultations 

Following the direction in the 

Presidential Memorandum to the 

Administrator (June 25, 2013),278 the 

EPA engaged in extensive and vigorous 

outreach to stakeholders and the general 

public at every stage of development of 

this rule. Our outreach has included 

direct engagement with the energy and 

environment officials in states, tribes, 

and a full range of stakeholders 

including leaders in the utility power 

sector, labor leaders, non-governmental 

organizations, other federal agencies, 

other experts, community groups and 

members of the public. The EPA 

participated in more than 300 meetings 

before the rule was proposed and more 

than 300 after the proposal. 

Throughout the rulemaking process, 

the agency has encouraged, organized, 

and participated in hundreds of 

meetings about CAA section 111(d) and 

reducing carbon pollution from existing 

power plants. The agency’s outreach 

prior to proposal, as well as during the 

public comment period, was designed to 

solicit policy ideas,279 concerns, and 

technical information. The agency 

received 4.3 million comments about all 

aspects of the proposed rule and 

thousands of people participated in the 

agency’s public hearings, webinars, 

listening sessions,280 teleconferences 

and meetings held all across the 

country. 

Our engagement has brought together 

a variety of states and stakeholders to 

discuss a wide range of issues related to 

the utility power sector and the 

development of emission guidelines 

under CAA section 111(d). The 

meetings were attended by the EPA 

Regional Administrators, other senior 

managers and staff who have been 

instrumental in the development of the 

rule and will play key roles in 

developing and implementing it. 

This outreach process has produced a 

wealth of information which has 

informed this rule significantly. The 

pre-proposal outreach efforts far 

exceeded what is required of the agency 

in the normal course of a rulemaking 

process, and the EPA expects that the 

dialogue with states and stakeholders 

will continue after the rule is finalized. 

The EPA recognizes the importance of 

working with all stakeholders, and in 

particular with the states, to ensure a 

clear and common understanding of the 

role the states will play in addressing 

carbon pollution from power plants. We 

firmly believe that our outreach has 

resulted in a more workable rule that 

will achieve the statutory goals and has 

enhanced the likelihood of timely and 

successful achievement of the carbon 

reduction goals, given the critical 

importance and urgency of the concrete 

action. 

The EPA has given stakeholder 

comments careful consideration and, as 

a result, this final rule includes features 

that are responsive to many stakeholder 

concerns. 

1. Public Hearings 

More than 2,700 people attended the 

public hearings sessions held in Atlanta, 

Denver, Pittsburgh, and Washington, 

DC. More than 1,300 people spoke at the 

public hearings. Additionally, about 100 

people attended the public hearing held 

in Phoenix, Arizona, on the November 

4, 2014 supplemental proposal. 

Speakers at the public hearings 

included Members of Congress, other 

public officials, industry 

representatives, faith-based 

organizations, unions, environmental 

groups, community groups, students, 

public health groups, energy groups, 

academia and concerned citizens. 

Participants shared a range of 

perspectives. Many were concerned 

with the impacts of climate change on 

their health and on future generations, 

others were worried about the impact of 

regulations on the economy. Their 

support for the agency’s efforts varied. 

2. State Officials 

Since fall 2013, the agency has 

provided multiple opportunities for the 

states to inform this rulemaking. 

Administrator McCarthy has engaged 

with governors from states with a 

variety of interests in the rulemaking. 

Other senior agency officials have 

engaged with every branch and major 

agency of state government—including 

state legislators, attorneys 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 


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submitted public comments from 

several agencies within each state. The 

wealth of comments and input from 

states was important in developing the 

final rulemaking. 

Agency officials listened to ideas, 

concerns and details from states, 

including from states with a wide range 

of experience in reducing carbon 

pollution from power plants. The EPA 

reached out to all 50 states to engage 

with both environmental and energy 

departments at all levels of government. 

As an example, a three-part webinar 

series in June/July 2014 for the states 

and tribes offered an interactive format 

for technical staff at the EPA and in the 

states/tribes to exchange ideas and ask 

clarifying question. The webinars were 

then posted online so other stakeholders 

could view them. A few weeks after the 

postings, the EPA organized follow-up 

conference calls with stakeholder 

groups. Also, the EPA hosted scores of 

technical meetings between states and 

the EPA in the weeks and months after 

the rule was proposed. 

Additionally, the EPA organized 

‘‘hub’’ calls; these teleconferences 

brought all of the states in a given EPA 

region together to discuss technical and 

interstate aspects of the proposal. These 

exchanges helped provide the 

stakeholders with the information they 

needed to comment on the proposal 

effectively. The EPA also held a series 

of webinars with state environmental 

associations and their members on a 

series of technical issues. 

The agency has collected policy 

papers and comment letters from states 

with overarching energy goals and 

technical details on the states’ utility 

power sector. EPA leadership and staff 

also participated in webinars and 

meetings with state and tribal officials 

hosted by collaborative groups and trade 

associations. After the comment period 

closed, and based on our meetings over 

the last year, as well as written 

comments on the proposal and NODA, 

the EPA analyzed information about 

data errors that needed to be addressed 

for the final rule. In February and March 

2015, we reached out to particular states 

to clarify ambiguous or unclear 

information that was submitted to the 

EPA related to NEEDS and eGRID data. 

The EPA contacted particular states to 

clarify the technical comments or 

concerns to ensure that any changes we 

make are accurate and appropriate. 

To help prepare for implementation of 

this rule, the agency initiated several 

outreach activities to assist with state 

planning efforts. The agency 

participated in meetings organized by 

the National Association of State Energy 

Officials (NASEO), the National 

Association of Regulatory Utility 

Commissioners (NARUC), and the 

National Association of Clean Air 

Agencies (NACAA) (the ‘‘3N’’ groups). 

Meeting participants discussed issues 

related to EE and RE. 

To help state officials prepare for the 

planning process that will take place in 

the states, the EPA presented a webinar 

on February 24, 2015. This webinar 

provided an update on training plans 

and further connection with states in 

the implementation process. Forty-nine 

states, the District of Columbia, and 14 

tribes were represented at this webinar. 

The EPA is developing a state plan 

electronic collection system to receive, 

track, and store state submittals of plans 

and reports. The EPA plans to use an 

integrated project team to solicit 

stakeholder input on the system during 

development. The team membership, 

including state representatives, will 

bring together the business and 

technology skills required to construct a 

successful product and promote 

transparency in the EPA’s 

implementation of the rule. 

To help identify training needs for the 

final Clean Power Plan, the agency 

reached out to a number of state and 

local organizations such as the Central 

State Air Resources Agencies and other 

such regional air agencies. The EPA’s 

outreach on training has included 

sharing the plans with the states and 

incorporating changes to the training 

topics based on the states’ needs. The 

EPA training plan includes a wide 

variety of topics such as basic training 

on the electric power sector as well as 

specific pollution control strategies to 

reduce carbon emissions from power 

plants. In particular, the states requested 

training on how to use programs such as 

combined heat and power, EE and RE to 

reduce carbon emissions. The EPA will 

continue to work with states to tailor 

training activities to their needs. 

The agency has engaged, and will 

continue to engage with states, 

territories, Washington, DC, 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 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, AkChin Indian Community, and Hope 

Tribe on November 18, 2014. The EPA 

held a consultation with the Ute Tribe 

of the Uintah and Ouray Reservation on 

December 16, 2014, and a consultation 

with the Gila River Indian Community 

on January 15, 2015. The EPA held a 

public hearing on the supplemental 

proposal on November 19, 2014, in 

Phoenix, Arizona. On April 28, 2015, 

the EPA held an additional consultation 

with the Navajo Nation. 

Tribes were interested in the impact 

of this rule on other ongoing regulatory 

actions at the affected EGUs, such as 

permitting or requirements for the best 

available retrofit technology (BART). 

Tribes also noted that it was important 

to allow RE projects on tribal lands to 

contribute toward meeting state goals. 

Some tribes indicated an interest in 

being involved in the development of 

implementation plans for areas of 

Indian country. Additional detail 

regarding the EPA’s outreach to tribes 

and comments and recommendations 

from tribes can be found in Section X.F 

of this preamble. 


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4. U.S. Territories 

The EPA has met with individual U.S. 

territories and affected EGUs in U.S. 

territories during the rulemaking 

process. On July 22, 2014, the EPA met 

with representatives from the Puerto 

Rico Environmental Quality Board, the 

Puerto Rico Electric Power Authority, 

the Governor’s Office, and the Office of 

Energy, Puerto Rico. On September 8, 

2014, the EPA held a meeting with 

representatives from the Guam 

Environmental Protection Agency 

(GEPA) and the Guam Power Authority 

and, on February 18, 2015, the EPA met 

again with representatives from GEPA. 

5. Industry Representatives 

Agency officials have engaged with 

industry leaders and representatives 

from trade associations in many one-onone 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 RE and EE. Other meetings have been 

held with representatives of energy 

intensive industries, such as the iron 

and steel and aluminum industries, to 

help understand the issues related to 

large industrial users of electricity. 

6. Electric Utility Representatives 

Agency officials participated in many 

meetings with utilities and their 

associations to discuss all aspects of the 

proposed guidelines. We have met with 

all types of companies that produce 

electricity, including private utilities or 

investor owned utilities. Public utilities 

and cooperative utilities were also part 

of in-depth conversations about CAA 

section 111(d) with EPA officials. 

The conversations included meetings 

with the EPA headquarters and regional 

offices. State officials were included in 

many of the meetings. Meetings with 

utility associations and groups of 

utilities were held with key EPA 

officials. The meetings covered 

technical, policy and legal topics of 

interest and utilities expressed a wide 

variety of support and concerns about 

CAA section 111(d). 

7. Electricity Grid Operators 

The EPA had a number of 

conversations with the ISOs and RTOs 

to discuss the rule and issues related to 

grid operations and reliability. EPA staff 

met with the ISO/RTO Council on 

several occasions to collect their ideas. 

The EPA regional offices also met with 

the ISOs and RTOs in their regions. 

System operators have offered 

suggestions in using regional 

approaches to implement CAA section 

111(d) while maintaining reliable, 

affordable electricity. 

8. Representatives from Community and 

Non-governmental Organizations 

Agency officials engaged with 

community groups representing 

vulnerable communities, and faithbased groups, among others, during the 

outreach effort. In response to a request 

from communities, the EPA held a daylong training on the Clean Power Plan 

on October 30, 2014, in Washington DC 

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. 

Public health groups discussed the 

need for protection of children’s health 

from harmful air pollution. Doctors and 

health care providers discussed the link 

between reducing carbon pollution and 

air pollution and public health. 

Consumer groups representing 

advocates for low income electricity 

customers discussed the need for 

affordable electricity. They talked about 

reducing electricity prices for 

consumers through EE and 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, lowincome communities and others during 

the outreach effort. Agency officials also 

engaged with the EPA’s National 

Environmental Justice Advisory Council 

(NEJAC) members in September 2013. 

The NEJAC is composed of 

stakeholders, including environmental 

justice leaders and other leaders from 

state and local government and the 

private sector. Additionally, the agency 

conducted a community call on 

February 26, 2015, and on February 27, 

2015, the EPA conducted a follow up 

webinar for participants in an October 

30, 2014 training session. The EPA also 

held a webinar for communities on the 

Clean Air Act (CAA) and section 111(d) 

of the CAA on April 2, 2015. The 

agency, in partnership with FERC and 

DOE, held two additional webinars for 

communities on the electricity grid and 

on energy markets on June 11, 2015, and 

July 9, 2015. 

During the EPA’s extensive outreach 

conducted before and after proposal, the 

EPA has heard a variety of issues raised 

by environmental justice communities. 

Communities expressed the desire for 

the agency to conduct an environmental 

justice (EJ) analysis and to require that 

states in the development of their state 

plans conduct one as well. Additionally, 

they asked that the agency require that 

states engage with communities in the 

development of their state plans and 

that the agency conduct meaningful 

involvement with communities, 

throughout the whole rulemaking 

process, including the implementation 

phase. Furthermore, communities 

stressed the importance of low-income 

and communities of color receiving the 

benefits of this rulemaking and being 

protected from being adversely 

impacted by this rulemaking. 

The purpose of this rule is to 

substantially reduce emissions of CO2, a 

key contributor to climate change, 

which adversely and disproportionately 

affects vulnerable and disadvantaged 

communities in the U.S. and around the 

world. In addition, the rule will result 

in substantial reductions of 

conventional air pollutants, providing 

immediate public health benefits to the 

communities where the facilities are 

located and for many miles around. The 

EPA is committed to ensuring that all 

Americans benefit from the public 

health and other benefits that this rule 

will bring. Further discussion of the 

impacts of this rule on vulnerable 

communities and actions that the EPA 

is taking to address concerns cited by 

communities is available in Sections IX 

and XII.J of this preamble. 

10. Labor 

Senior agency officials met with a 

number of labor union representatives 

about reducing carbon pollution using 

CAA section 111(d). Those unions 

included: The United Mine Workers of 

America; the Sheet Metal, Air, Rail and 

Transportation Union (SMART); the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64707 

International Brotherhood of 

Boilermakers, Iron Ship Builders, 

Blacksmiths, Forgers and Helpers (IBB); 

United Association of Journeymen and 

Apprentices of the Plumbing and Pipe 

Fitting Industry of the United States and 

Canada; the International Brotherhood 

of Electrical Workers (IBEW); and the 

Utility Workers Union of America. In 

addition, agency leaders met with the 

Presidents of several unions and the 

President of the American Federation of 

Labor-Congress of Industrial 

Organizations (AFL–CIO) at the AFL– 

CIO headquarters. 

EPA officials attended meetings 

sponsored by labor unions to give 

presentations and engage in discussions 

about reducing carbon pollution using 

CAA section 111(d). These included 

meetings sponsored by the IBB and the 

IBEW. 

11. Other Federal Agencies and 

Independent Agencies 

Throughout the development of the 

rulemaking, the EPA consulted with 

other federal agencies with relevant 

expertise. For example, the EPA met 

with managers from the U.S. 

Department of Agriculture’s (USDA’s) 

Rural Utility Service to discuss the rule 

and potential effects on affected EGUs 

in rural areas and how USDA programs 

could interact with affected EGUs 

during rule implementation. 

The U.S. Department of Energy (DOE) 

was a frequent source of expertise on 

the proposed and final rule. EPA 

management and staff had numerous 

meetings with management and staff at 

DOE on a range of topics, including the 

effectiveness and costs of energy 

generation technologies, and EE. 

DOE provided technical assistance 

relating to RE and demand-side EE, 

including RE and demand-side EE cost 

and performance data and, for RE, 

information on the feasibility of 

deploying and reliably integrating 

increased RE generation. Further, EPA 

and DOE staff discussed emission 

measurement and verification (EM&V) 

strategies. 

The EPA also consulted with DOE on 

electric reliability issues. EPA staff and 

managers met and spoke with DOE staff 

and managers throughout the 

development of the proposed and final 

rules on topic related to electric system 

reliability. 

EPA officials worked closely with 

DOE and Federal Energy Regulatory 

Commission (FERC) officials to ensure, 

to the greatest extent possible, that 

actions taken by states and affected 

EGUs to comply with the final rule 

mitigate potential electric system 

reliability issues. Senior EPA officials 

met with each of the FERC 

Commissioners and EPA staff had 

frequent contact with FERC staff 

throughout the development the rule. 

FERC held four technical conferences to 

discuss implications of compliance 

approaches to the rule for electric 

reliability. EPA staff attended the four 

conferences and EPA leadership spoke 

at all of them. The EPA, DOE, and FERC 

will continue to work together to ensure 

electric grid reliability in the 

development and implementation of 

state plans. 

L. Comments on the Proposal 

The Administrator signed the 

proposed emission guidelines on June 2, 

2014, and, on the same day, the EPA 

made this version available to the public 

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

The 120-day public comment period on 

the proposal began on June 18, 2014, the 

day of publication of the proposal in the 

Federal Register. On September 18, 

2014, in response to requests from 

stakeholders, the EPA extended the 

comment period by 45 days, to 

December 1, 2014, giving stakeholders 

over 165 days to review and comment 

upon the proposal. Stakeholders also 

had the opportunity to comment on the 

NODA, as well as the Federal Register 

document and TSD regarding potential 

methods for determining the mass that 

is equivalent to an emission rate-based 

CO2 goal, through December 1, 2014. 

The EPA offered a separate 45-day 

comment period for the November 4, 

2014 supplemental proposal, and that 

comment period closed on December 

19, 2014. 

The EPA received more than 4.2 

million comments on the proposed 

carbon pollution emission guidelines 

from a range of stakeholders that 

included, including state environmental 

and energy officials, local government 

officials, tribal officials, public utility 

commissioners, system operators, 

utilities, public interest advocates, and 

members of the public. The agency 

received comments on many aspects of 

the proposal and many suggestions for 

changes that would address issues of 

concern. 

III. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

The EPA is establishing emission 

guidelines for states to use in 

developing plans to address GHG 

emissions from existing fossil fuel-fired 

electric generating units. The emission 

guidelines are based on the EPA’s 

determination of the ‘‘best system of 

emission reduction . . . adequately 

demonstrated’’ (BSER) and include 

source category-specific CO2 emission 

performance rates, state-specific goals, 

requirements for state plan components, 

and requirements for the process and 

timing for state plan submittal and 

compliance. 

Under CAA section 111(d), the states 

must establish standards of performance 

that reflect the degree of emission 

limitation achievable through the 

application of the ‘‘best system of 

emission reduction’’ that, taking into 

account the cost of achieving such 

reduction and any non-air quality health 

and environmental impact and energy 

requirements, the Administrator 

determines has been adequately 

demonstrated. 

The EPA has determined that the 

BSER is the combination of emission 

rate improvements and limitations on 

overall emissions at affected EGUs that 

can be accomplished through the 

following three sets of measures or 

building blocks: 

1. Improving heat rate at affected coal-fired 

steam EGUs. 

2. Substituting increased generation from 

lower-emitting existing natural gas combined 

cycle units for generation from higheremitting affected steam generating units. 

3. Substituting increased generation from 

new zero-emitting RE generating capacity for 

generation from affected fossil fuel-fired 

generating units. 

Consistent with CAA section 111(d) 

and other rules promulgated under this 

section, the EPA is taking a traditional, 

performance-based approach to 

establishing emission guidelines for 

affected sources and applying the BSER 

to two source subcategories of existing 

fossil fuel-fired EGUs—fossil fuel-fired 

electric utility steam generating units 

and stationary combustion turbines. The 

EPA is finalizing source subcategoryspecific emission performance rates that 

reflect the EPA’s application of the 

BSER. For fossil fuel-fired steam 

generating units, we are finalizing a 

performance rate of 1,305 lb CO2/MWh. 

For stationary combustion turbines, we 

are finalizing a performance rate of 771 

lb CO2/MWh. The EPA has also 

translated the source subcategoryspecific CO2 emission performance rates 

into equivalent statewide rate-based and 

mass-based CO2 goals and is providing 

those as an option for states to use. 

Under CAA section 111(d), each state 

must develop, adopt, and then submit 

its plan to the EPA. For its CAA section 

111(d) plan, a state will determine 

whether to apply these emission 

performance rates to each affected EGU, 

individually or together, or to take an 

alternative approach and meet either an 

equivalent statewide rate-based goal or 

an equivalent statewide mass-based 


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64708 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

281 In the case of a tribe that has one or more 

affected EGUs in its area of Indian country, the tribe 

has the opportunity, but not the obligation, to 

establish a CO2 emission standard for each affected 

EGU located in its area of Indian country and a 

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

country. If the tribe chooses to establish its own 

plan, it must seek and obtain authority from the 

EPA to do so pursuant to 40 CFR 49.9. If it chooses 

not to seek this authority, the EPA has the 

responsibility to determine whether it is necessary 

or appropriate, in order to protect air quality, to 

establish a CAA section 111(d) plan for an area of 

Indian country where affected EGUs are located. 

282A 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. 

283The 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. 

goal, as provided by the EPA in this 

rulemaking. 

States with one or more affected EGUs 

will be required to develop and 

implement plans that set emission 

standards for affected EGUs. The CAA 

section 111(d) emission guidelines that 

the EPA is promulgating in this action 

apply to only the 48 contiguous states 

and any Indian tribe that has been 

approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and 

implement a CAA section 111(d) 

plan.281 Because Vermont and the 

District of Columbia do not have 

affected EGUs, they will not be required 

to submit a state plan. Because the EPA 

does not possess all of the information 

or analytical tools needed to quantify 

the BSER for the two non-contiguous 

states with otherwise affected EGUs 

(Alaska and Hawaii) and the two U.S. 

territories with otherwise affected EGUs 

(Guam and Puerto Rico), these emission 

guidelines do not apply to those areas, 

and those areas will not be required to 

submit state plans on the schedule 

required by this final action. 

In developing its CAA section 111(d) 

plan, a state will have the option of 

choosing from two different approaches: 

(1) An ‘‘emission standards’’ approach, 

or (2) a ‘‘state measures’’ approach. With 

an emission standards approach, a state 

will apply all requirements for 

achieving the subcategory-specific CO2

emission performance rates or the statespecific 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 final plan submittals by September 

6, 2016, or to make an initial submittal 

by this date in order to obtain an 

extension for making their final plan 

submittals no later than September 6, 

2018, which is 3 years from the 

signature date of the rule. In order to 

receive an extension, states, in the 

initial submittal, must address three 

required components sufficiently to 

demonstrate that a state is able to 

undertake steps and processes necessary 

to timely submit a final plan by the 

extended date of September 6, 2018. 

The first required component is 

identification of final plan approach or 

approaches under consideration, 

including a description of progress 

made to date. The second required 

component is an appropriate 

explanation for why the state requires 

additional time to submit a final plan 

beyond September 6, 2016. The third 

required component for states to address 

in the initial submittal is a 

demonstration of how they have been 

engaging with the public, including 

vulnerable communities, and a 

description of how they intend to 

meaningfully engage with community 

stakeholders during the additional time 

(if an extension is granted) for 

development of the final plan. 

Affected EGUs must achieve the final 

emission performance rates or 

equivalent state goals by 2030 and 

maintain that level thereafter. The EPA 

is establishing an 8-year interim period 

over which states must achieve the full 

required reductions to meet the CO2

performance rates, and this begins in 

2022. This 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 that states must meet, as explained 

in Section VI of this preamble. 

For the final emission guidelines, the 

EPA is revising the list of components 

required in a final state plan submittal 

to reflect: (1) Components required for 

all state plan submittals; (2) components 

required for the emission standards 

approach; and (3) components required 

for the state measures approach. The 

revised list of components also reflects 

the approvability criteria, which are no 

longer separate from the state plan 

submittal components. 

All state plans must include the 

following components: 

• Description of the plan approach and 

geographic scope 

• Identification of the state’s CO2 interim 

period goal (for 2022–2029), interim steps 

(interim step goal 1 for 2022–2024; 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 282

• State recordkeeping and reporting 

requirements 

• Certification of hearing on state plan 

• Supporting documentation 

Also, in all state plans, as part of the 

supporting documentation, a state must 

include a description of how they 

considered reliability in developing its 

state plan. 

State plan submittals using the 

emission standards approach must also 

include: 

• Identification of each affected EGU; 

identification of federally enforceable 

emission standards for the affected EGUs; 

and monitoring, recordkeeping and reporting 

requirements. 

• Demonstrations that each emission 

standard will result in reductions that are 

quantifiable, non-duplicative, permanent, 

verifiable, and enforceable. 

State plan submittals using the state 

measures approach must also include: 

• Identification of each affected EGU; 

identification of federally enforceable 

emission standards for affected EGUs (if 

applicable); identification of backstop of 

federally enforceable emission standards; and 

monitoring, recordkeeping and reporting 

requirements. 

• Identification of each state measure and 

demonstration that each state measure will 

result in reductions that are quantifiable, 

non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, 

each state plan must follow the EPA 

implementing regulations at 40 CFR 

60.23. 

If a state with affected EGUs does not 

submit a plan or if the EPA does not 

approve a state’s plan, then under CAA 

section 111(d)(2)(A), the EPA must 

establish a plan for that state. A state 

that has no affected EGUs must 

document this in a formal negative 

declaration submitted to the EPA by 

September 6, 2016. In the case of a tribe 

that has one or more affected EGUs in 

its area of Indian country,283 the tribe 

has the opportunity, but not the 

obligation, to establish a CAA section 

111(d) plan for its area of Indian 

country. If a tribe with one or more 

affected EGUs located in its area of 


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284Under CAA section 111(d), there is no 

requirement that the EPA make a finding that the 

emissions from existing sources that are the subject 

of regulation cause or contribute significantly to air 

pollution which may reasonably be anticipated to 

endanger public health or welfare. As predicates to 

promulgating regulations under CAA section 111(d) 

for existing sources, the EPA must make 

endangerment and cause-or-contribute-significantly 

findings for emissions from the source category, and 

the EPA must promulgate regulations for new 

sources in the source category. In the CAA section 

111(b) rule for CO2 emissions for new affected EGUs 

that the EPA is promulgating concurrently with this 

rule, the EPA discusses the endangerment and 

cause-or-contribute-significantly findings and 

explains why the EPA has already made them for 

the affected EGU source categories so that the EPA 

is not required to make them for CO2 emissions 

from affected EGUs, and, in the alternative, why, if 

the EPA were required to make those findings, it 

was making them in that rulemaking. 

285The EPA is not re-opening that interpretation 

in this rulemaking. 

Indian country does not submit a plan 

or does not receive EPA approval of a 

submitted plan, the EPA has the 

responsibility to establish a CAA section 

111(d) plan for that area if it determines 

that such a plan is necessary or 

appropriate. 

During implementation of its 

approved state plan, each state must 

demonstrate to the EPA that its affected 

EGUs are meeting the interim and final 

performance requirements included in 

this final rule through monitoring and 

reporting requirements. State plan 

requirements and flexibilities are 

described more fully in Section VIII of 

this preamble. 

B. Brief Summary of Legal Basis 

This rule is consistent with the 

requirements of CAA section 111(d) and 

the implementing regulations.284 As an 

initial matter, the EPA reasonably 

interprets the provisions identifying 

which air pollutants are covered under 

CAA section 111(d) to authorize the 

EPA to regulate CO2 from fossil fuelfired EGUs. In addition, the EPA 

recognizes that CAA section 111(d) 

applies to sources that, if they were new 

sources, would be covered under a CAA 

section 111(b) rule. Concurrently with 

this rule, the EPA is finalizing a CAA 

section 111(b) rulemaking establishing 

standards of performance for CO2

emissions from new fossil fuel-fired 

EGUs, from modified fossil fuel-fired 

EGUs, and from reconstructed fossil 

fuel-fired EGUs, and any of those sets of 

section 111(b) standards of performance 

provides the requisite predicate for this 

rulemaking. 

A key step in promulgating 

requirements under CAA section 

111(d)(1) is determining the ‘‘best 

system of emission reduction which 

. . . the Administrator determines has 

been adequately demonstrated’’ (BSER) 

under CAA section 111(a)(1). It is clear 

by the terms of section 111(a)(1) and the 

implementing regulations for section 

111(d) that the EPA is authorized to 

determine the BSER; 285 accordingly, in 

this rulemaking, the EPA is determining 

the BSER. 

The EPA is finalizing the BSER for 

fossil fuel-fired EGUs based on building 

blocks 1, 2, and 3. Building block 1 

includes operational improvements and 

equipment upgrades that the coal-fired 

steam-generating EGUs in the state may 

undertake to improve their heat rate. It 

qualifies as part of the BSER because it 

improves the carbon intensity of the 

affected EGUs in generating electricity 

through actions the affected sources 

may undertake that are adequately 

demonstrated and whose cost is 

‘‘reasonable.’’ Building blocks 2 and 3 

include increases in low- or zeroemitting generation which substitute for 

generation from the affected EGUs and 

thereby reduce CO2 emissions from 

those sources. All of these measures are 

components of a ‘‘system of emission 

reduction’’ for the affected EGUs 

because they entail actions that the 

affected EGUs may themselves 

undertake that have the effect of 

reducing their emissions. Further, these 

measures meet the criteria in CAA 

section 111(a)(1) and the case law for 

the ‘‘best’’ system of emission reduction 

that is ‘‘adequately demonstrated’’ 

because they achieve the appropriate 

level of reductions, their cost is 

‘‘reasonable,’’ they do not have adverse 

non-air quality health and 

environmental impacts or impose 

adverse energy requirements, and they 

are each well-established among 

affected EGUs. It should be emphasized 

that these measures are consistent with 

current trends in the electricity sector. 

Building blocks 2 and 3 may be 

implemented through a set of measures, 

including reduced generation from the 

fossil fuel-fired EGUs. These measures 

do not, however, reduce the amount of 

electricity that can be sold or that is 

available to end users. In addition, 

states should be expected to allow their 

affected EGUs to trade rate-based 

emission credits or mass-based emission 

allowances (trading) because trading is 

well-established for this industry and 

has the effect of focusing costs on the 

affected EGUs for which reducing 

emissions is most cost-effective. 

Because trading facilitates 

implementation of the building blocks 

and may help to optimize costeffectiveness, trading is a method of 

implementing the BSER as well. 

As a result, an affected EGU has a set 

of choices for achieving its emission 

standards. For example, an affected 

coal-fired steam generating unit can 

achieve a rate-based standard through a 

set of actions that implement the 

building block 1 measures and that 

implement the building block 2 and 3 

measures through a set of actions that 

range from purchasing full or partial 

interest in existing NGCC or new RE 

assets to purchasing ERCs that represent 

the environmental attributes of 

increased NGCC generation or new 

renewable generation. In addition, the 

affected EGU may reduce its generation 

and thereby reduce the extent that it 

needs to implement the building blocks. 

The affected EGU may also purchase 

rate-based emission credits from other 

affected EGUs. If the state chooses to 

impose a mass-based emission standard, 

the coal-fired steam generating unit may 

implement building block 1 measures, 

purchase mass-based emission 

allowances from other affected EGUs, or 

reduce its generation. In light of the 

available sources of lower- and zeroemitting replacement generation, this 

approach would achieve an appropriate 

level of emission reductions and 

maintain the reliability of the electricity 

system. 

With the promulgation of the 

emission guidelines, each state must 

develop and submit a plan to achieve 

the CO2 emission performance rates 

established by the EPA or the equivalent 

statewide rate-based or mass-based goal 

provided by the EPA in this rule. The 

EPA interprets CAA section 111(d) to 

allow states to establish standards of 

performance and provide for their 

implementation and enforcement 

through either the ‘‘emission standards’’ 

or the ‘‘state measures’’ plan type. In the 

case of the ‘‘emission standards’’ plan 

type, the emission standards establish 

standards of performance, and the other 

components of the plan provide for their 

implementation and enforcement. In the 

case of the ‘‘state measures’’ plan type, 

–the state submits a plan that relies 

upon measures that are only enforceable 

as a matter of state law that will, in 

conjunction with any emission 

standards on affected EGUs, result in 

the achievement of the applicable 

performance rates or state goals by the 

affected EGUs. Under the state measures 

plan type, states must also submit a 

federally enforceable backstop and a 

mechanism that would trigger 

implementation of the backstop; 

therefore, in a state measures plan, the 

standards of performance take the form 

of the backstop, the trigger mechanism 

provides for the implementation of such 

backstop, and the other required 

components of the plan provide for 


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286Section 111(d) might be read to apply to HAP 

under certain circumstances. However, because 

carbon dioxide is not a HAP, this issue does not 

need to be resolved in the context of this rule. 

287For example, in the CAMR litigation (State of 

New Jersey v. EPA, No. 05–1097 (D.C. Cir.), the joint 

brief filed by a group of intervenors and an amicus 

(including six states and the West Virginia 

Department of Environmental Protection, and 

Utility Air Regulatory Group and nine other 

industry entities) stated that the EPA had 

interpreted section 111(d) in light of the two 

different amendments and that the EPA’s 

interpretation was ‘‘a reasoned way to reconcile the 

conflicting language and the Court should defer to 

the EPA’s interpretation.’’ Joint Brief of State 

Respondent-Intervenors, Industry RespondentIntervernors, and State Amicus, filed May 18, 2007, 

at 25. 

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 significant flexibility to take local 

circumstances and state policy goals 

into account in determining how to 

reduce emissions from its affected 

sources, as long as the plan meets 

minimum federal requirements. 

Both state plan types, and the 

standards of performance for the 

affected EGUs that the states will 

establish through the state plan process, 

are consistent with the applicable CAA 

section 111 provisions. A state has 

discretion in determining the 

appropriate measures to rely upon for 

its plan. The state may adopt measures 

that assure the achievement of the 

requisite CO2 emission performance rate 

or state goal by the affected EGUs, and 

is not limited to the measures that the 

EPA identifies as part of the BSER. 

In this rulemaking, the EPA 

establishes reasonable deadlines for 

state plan submission. Under CAA 

section 111(d)(1), state plans must 

‘‘provide for implementation and 

enforcement’’ of the standards of 

performance, and under CAA section 

111(d)(2), the state plans must be 

‘‘satisfactory’’ for the EPA to approve 

them. In this rulemaking, the EPA is 

finalizing the criteria that the state plans 

must meet under these requirements. 

The EPA discusses its legal 

interpretation in more detail in other 

parts of this preamble and provides 

additional information about certain 

issues in the Legal Memorandum 

included in the docket for this 

rulemaking. 

IV. Authority for This Rulemaking, 

Definition of Affected Sources, and 

Treatment of Source Categories 

A. EPA’s Authority Under CAA Section 

111(d) 

EPA’s authority for this rule is CAA 

section 111(d). CAA section 111(d) 

provides that the EPA will promulgate 

regulations under which each state will 

establish standards of performance for 

existing sources for any air pollutant 

that meets two criteria. First, CAA 

section 111(d) applies to air pollutants 

that are not regulated as a criteria 

pollutant under section 108 or as a 

hazardous air pollutant (HAP) under 

CAA section 112. 42 U.S.C. 

7411(d)(1)(A)(i).286 Second, section 

111(d) applies only to air pollutants for 

which the existing source would be 

regulated under section 111 if it were a 

new source. 42 U.S.C. 7411(d)(1)(A)(ii). 

Here, carbon dioxide (CO2) meets both 

criteria: (1) It is not a criteria pollutant 

regulated under section 108 nor a HAP 

regulated under CAA section 112, and 

(2) CO2 emissions from new power 

plants (including newly constructed, 

modified and reconstructed power 

plants) are regulated under the CAA 

section 111(b) rule that is being 

finalized along with this rule. 

B. CAA Section 112 Exclusion to CAA 

Section 111(d) Authority 

CAA section 111(d) contains an 

exclusion that limits the regulation 

under CAA section 111(d) of air 

pollutants that are regulated under CAA 

section 112. 42 U.S.C. 7411(d)(1)(A)(i). 

This ‘‘Section 112 Exclusion’’ in CAA 

section 111(d) was the subject of a 

significant number of comments based 

on two differing amendments to this 

exclusion enacted in the 1990 CAA 

Amendments. As discussed in more 

detail below, the House and the Senate 

each initially passed different 

amendments to the Section 112 

Exclusion and both amendments were 

ultimately passed by both houses and 

signed into law. In 2005, in connection 

with the Clean Air Mercury Rule 

(CAMR), the EPA discussed the agency’s 

interpretation of the Section 112 

Exclusion in light of these two differing 

amendments and concluded that the 

two amendments were in conflict and 

that the provision should be read as 

follows to give both amendments 

meaning: where a source category has 

been regulated under CAA section 112, 

a CAA section 111(d) standard of 

performance cannot be established to 

address any HAP listed under CAA 

section 112(b) that may be emitted from 

that particular source category. See 70 

FR 15994, 16029–32 (March 29, 2005). 

In June 2014, the EPA presented this 

previous interpretation as part of the 

proposal and requested comment on it. 

The EPA received numerous comments 

on its previous interpretation, including 

comments on the proper interpretation 

and effect of each of the two differing 

amendments, and whether the Section 

112 Exclusion should be read to mean 

that the EPA’s regulation of HAP from 

power plants under CAA section 112 

bars the EPA from establishing CAA 

section 111(d) regulations covering CO2

emissions from power plants. In 

particular, many comments focused on 

two specific issues. First, some 

commenters—including some industry 

and state commenters that had 

previously endorsed the EPA’s 

interpretation of the Section 112 

Exclusion in other contexts 287—argued 

that the EPA’s 2005 interpretation was 

in error because it allowed the 

regulation of certain pollutants from 

source categories under CAA section 

111(d) when those source categories 

were also regulated for different 

pollutants under CAA section 112. 

Second, some commenters argued that 

the EPA’s previous interpretation of the 

House amendment (as originally 

represented in 2005 at 70 FR at 16029– 

30) was in error because it improperly 

read that amendment as focusing on 

whether a source category was regulated 

under CAA section 112 rather than on 

whether the air pollutant was regulated 

under CAA section 112, and that 

improper reading lead to an 

interpretation that was inconsistent 

with the structure and purpose of the 

CAA. 

In light of the comments, the EPA has 

reconsidered its previous interpretation 

of the Section 112 Exclusion and, in 

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 


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288 In subsequent CAA amendments, Congress has 

maintained this three-part scheme, but 

supplemented it with the Preservation of 

Significant Deterioration (PSD) program, the Acid 

Rain Program and the Regional Haze program. 

289Originally, when the House bill to amend the 

CAA was introduced in January 1989, it focused on 

amendments to control HAP. Of particular note, the 

amendments to section 112 included a provision 

that excluded regulation under section 112 of 

‘‘[a]ny air pollutant which is included on the list 

under section 108(a), or which is regulated for a 

source category under section 111(d).’’ H.R. 4, § 2 

(Jan. 3, 1989), 1990 CAA Legist. Hist. at 4046. In 

other words, the Section 112 Exclusion in section 

111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be 

called a ‘‘Section 111(d) Exclusion’’ in section 112. 

This is significant because the ‘‘source category’’ 

phrasing in the original January 1989 text with 

respect to section 111(d) makes sense, whereas the 

‘‘source category’’ phrasing in the 1990 House 

amendment does not. When referring to the scope 

of what is regulated under section 111(d), it makes 

sense to frame that scope with respect to source 

Continued 

has concluded that the two differing 

amendments are not properly read as 

conflicting. Instead, the House 

amendment and the Senate Amendment 

should each be read to mean the same 

in the context presented by this rule: 

that the Section 112 Exclusion does not 

bar the regulation under CAA section 

111(d) of non-HAP from a source 

category, regardless of whether that 

source category is subject to standards 

for HAP under CAA section 112. In 

reaching this conclusion, the EPA has 

revised its previous interpretation of the 

House amendment, as discussed below. 

1. Structure of the CAA and Pre-1990 

Section 112 Exclusion 

The Clean Air Act sets out a 

comprehensive scheme for air pollution 

control, addressing three general 

categories of pollutants emitted from 

stationary sources: (1) Criteria 

pollutants (which are addressed in 

sections 108–110); (2) hazardous 

pollutants (which are addressed under 

section 112); and (3) ‘‘pollutants that are 

(or may be) harmful to public health or 

welfare but are not or cannot be 

controlled under sections 108–110 or 

112.’’ 40 FR 53340 (Nov. 17, 1975). 

Six ‘‘criteria’’ pollutants are regulated 

under sections 108–110. These are 

pollutants that the Administrator has 

concluded ‘‘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. 

HAP are regulated under CAA section 

112 and include the pollutants listed by 

Congress in section 112(b)(1) and other 

pollutants that the EPA lists under 

sections 112(b)(2) and (b)(3). CAA 

section 112 further provides that the 

EPA will publish and revise a list of 

‘‘major’’ and ‘‘area’’ source categories of 

HAP, and then establish emissions 

standards for HAP emitted by sources 

within each listed category. 42 U.S.C. 

7412(c)(1) & (2). 

CAA section 111, 42 U.S.C. 7411, is 

the third part of the CAA’s structure for 

regulating stationary sources. Section 

111 has two main components. First, 

section 111(b) requires the EPA to 

promulgate federal ‘‘standards of 

performance’’ addressing new stationary 

sources that cause or contribute 

significantly to ‘‘air pollution which 

may reasonably be anticipated to 

endanger public health or welfare.’’ 42 

U.S.C. 7411(b)(1)(A). Once the EPA has 

set new source standards addressing 

emissions of a particular pollutant 

under CAA section 111(b), CAA section 

111(d) provides that the EPA will 

promulgate regulations requiring states 

to establish standards of performance 

for existing stationary sources of the 

same pollutant. 42 U.S.C. 7411(d)(1). 

Together, the criteria pollutant/

NAAQS provisions in sections 108–110, 

the hazardous air pollutant provisions 

in section 112, and performance 

standard provisions in section 111 

constitute a comprehensive scheme to 

regulate air pollutants with ‘‘no gaps in 

control activities pertaining to 

stationary source emissions that pose 

any significant danger to public health 

or welfare.’’ S. Rep. No. 91–1196, at 20 

(1970).288

The specific role of CAA section 

111(d) in this structure can be seen in 

CAA subsection 111(d)(1)(A)(i), which 

provides that regulation under CAA 

section 111(d) is intended to cover 

pollutants that are not regulated under 

either the criteria pollutant/NAAQS 

provisions or 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 not covered by the criteria 

pollutant provisions or the hazardous 

air pollutant provisions. 

This gap-filling purpose can be seen 

in the early legislative history of the 

CAA. As originally enacted in the 1970 

CAA, the precursor to CAA section 111 

(which was originally section 114) was 

described as covering pollutants that 

would not be controlled by the criteria 

pollutant provisions or the hazardous 

air pollutant provisions. See S. 

Committee Rep. to accompany S. 4358 

(Sept. 17, 1970), 1970 CAA Legis. Hist. 

at 420 (‘‘It should be noted that the 

emission standards for pollutants which 

cannot be considered hazardous (as 

defined in section 115 [which later 

became section 112]) could be 

established under section 114 [later, 

section 111]. Thus, there should be no 

gaps in control activities pertaining to 

stationary source emissions that pose 

any significant danger to public health 

or welfare.’’); Statement by S. Muskie, S. 

Debate on S. 4358 (Sept. 21, 1970), 1970 

CAA Legis. Hist. at 227 (‘‘[T]he bill [in 

section 114] provides the Secretary with 

the authority to set emission standards 

for selected pollutants which cannot be 

controlled through the ambient air 

quality standards and which are not 

hazardous substances.’’). 

2. The 1990 Amendments to the Section 

112 Exclusion 

The Act was amended extensively in 

1990. Among other things, Congress 

sought to accelerate the EPA’s 

regulation of hazardous pollutants 

under section 112. To that end, 

Congress established a lengthy list of 

HAP; set criteria for listing ‘‘source 

categories’’ of such pollutants; and 

required the EPA to establish standards 

for each listed source category’s 

hazardous pollutant emissions. 42 

U.S.C. 7412(b), (c) and (d). In the course 

of overhauling the regulation of HAP 

under section 112, Congress needed to 

edit section 111(d)’s reference to section 

112(b)(1)(A), which was to be 

eliminated as part of the revisions to 

section 112. 

To address the obsolete crossreference to section 7412(b)(1)(A), 

Congress passed two differing 

amendments—one from the Senate and 

one from the House—that were never 

reconciled in conference. The Senate 

amendment replaced the cross reference 

to old section 112(b)(1)(A) with a crossreference to new section 112. Pub. L. 

101–549, § 302(a), 104 Stat. 2399, 2574 

(1990). The House amendment replaced 

the cross-reference with the phrase 

‘‘emitted from a source category which 

is regulated under section [112].’’ Pub. 

L. 101–549, § 108(g), 104 Stat. 2399, 

2467 (1990).289 Both amendments were 


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categories, because section 111 regulation begins 

with the identification of source categories under 

section 111(b)(1)(A). By contrast, regulation under 

section 112 begins with the identification of HAP 

under section 112(b); the listing of source categories 

under section 112(c) is secondary to the listing of 

HAP. From this history, and in light of this 

difference between the scope of what is regulated 

in sections 111 and 112, it is reasonable to conclude 

that the ‘‘source category’’ phrasing is a legacy from 

the original 1989 bill—that is, when converting the 

1989 text into the Section 112 Exclusion that we see 

in the 1990 House amendment, the legislative 

drafters continued to use phrasing based on ‘‘source 

category’’ notwithstanding that this phrasing 

created a mismatch with the way that the scope of 

section 112 regulation is determined. 

enacted into law, and thus both are part 

of the current CAA. To determine how 

this provision is properly applied in 

light of the two differing amendments, 

we first look at the Senate amendment, 

then at the House amendment, then 

discuss how the two amendments are 

properly read together. 

3. The Senate Amendment is Clear and 

Unambiguous 

Unlike the ambiguous amendment to 

CAA section 111(d) in the House 

amendment (discussed below), the 

Senate amendment is straightforward 

and unambiguous. It maintained the 

pre-1990 meaning of the Section 112 

Exclusion by simply substituting 

‘‘section 112(b)’’ for the prior crossreference to ‘‘section 112(b)(1)(A).’’ Pub. 

L. 101–549, § 302(a), 104 Stat. 2399, 

2574 (1990). So amended, CAA section 

111(d) mandates that the EPA require 

states to submit plans establishing 

standards for ‘‘any air pollutant . . . 

which is not included on a list 

published under section [108(a)] or 

section [112(b)].’’ Thus, the Section 112 

Exclusion resulting from the Senate 

amendment would preclude CAA 

section 111(d) regulation of HAP 

emission but would not preclude CAA 

section 111(d) regulation of CO2

emissions from power plants 

notwithstanding that power plants are 

also regulated for HAP under CAA 

section 112. 

Some commenters have argued that 

the Senate amendment should be given 

no effect, because only the House 

amendment is shown in the U.S. Code, 

and because the Senate amendment 

appeared under the heading 

‘‘conforming amendments,’’ and for 

various other reasons. The EPA 

disagrees. The Senate amendment, like 

the House amendment, was enacted into 

law as part of the 1990 CAA 

amendments, and must be given effect. 

First, that the U.S. Code only reflects 

the House amendment does not change 

the fact that both amendments were 

signed into law as part of the 1990 

Amendments, as shown in the Statutes 

at Large. Pub. L. 101–549, §§ 108(g) and 

302(a), 104 Stat. 2399, 2467, 2574 

(1990). Where there is a conflict 

between the U.S. Code and the Statutes 

at Large, the latter controls. See 1 U.S.C. 

112 & 204(a); Stephan v. United States, 

319 U.S. 423, 426 (1943) (‘‘the Code 

cannot prevail over the Statutes at Large 

when the two are inconsistent’’); Five 

Flags Pipe Line Co. v. Dep’t of Transp., 

854 F.2d 1438, 1440 (D.C. Cir. 1988) 

(‘‘[W]here the language of the Statutes at 

Large conflicts with the language in the 

United States Code that has not been 

enacted into positive law, the language 

of the Statutes at Large controls.’’). 

Second, the ‘‘conforming’’ label is 

irrelevant. A ‘‘conforming’’ amendment 

may be either substantive or nonsubstantive. Burgess v. United States, 

553 U.S. 124, 135 (2008). And while the 

House Amendment contains more 

words, it also qualifies as a ‘‘conforming 

amendment’’ under the definition in the 

Senate Legislative Drafting Manual, 

Section 126(b)(2) (defining ‘‘conforming 

amendments’’ as those ‘‘necessitated by 

the substantive amendments of 

provisions of the bill’’). Here, both the 

House and Senate amendments were 

‘‘necessitated by’’ Congress’ revisions to 

section 112 in the 1990 CAA 

Amendment, which included the 

deletion of old section 112(b)(1)(A). 

Thus, the House’s amendment is no less 

‘‘conforming’’ than the Senate’s, and the 

heading under which it was enacted 

(‘‘Miscellaneous Guidance’’) does not 

suggest any more importance than 

‘‘Conforming Amendments.’’ In any 

event, courts gives full effect to 

conforming amendments, see 

Washington Hosp. Ctr. v. Bowen, 795 

F.2d 139, 149 (D.C. Cir. 1986), and so 

neither the Senate Amendment nor the 

House amendment can be ignored. 

Third, the legislative history of the 

Senate amendment supports the 

conclusion that the substitution of the 

updated cross-reference was not a 

mindless, ministerial decision, but 

reflected a decision to choose an update 

of the cross reference instead of the text 

that was inserted into the Section 112 

Exclusion by the House amendment. In 

mid-1989, the House and Senate 

introduced identical bills (H.R. 3030 

and S. 1490, respectively) to provide for 

‘‘miscellaneous’’ changes to the CAA. In 

both the Senate and House bills as they 

were introduced in mid-1989, the 

Section 112 Exclusion was to be 

amended by taking out ‘‘or 112(b)(1)(A)’’ 

and inserting ‘‘or emitted from a source 

category which is regulated under 

section 112.’’ H.R. 3030, as introduced, 

101st Cong. § 108 (Jul. 27, 1989); S. 

1490, as introduced, 101st Cong. § 108 

(Aug. 3, 1989). See 1990 CAA Legis. 

Hist. at 3857 (noting that H.R. 3030 and 

S.1490, as introduced, were the same). 

Although S. 1490 was identical to H.R. 

3030 when they were introduced, the 

Senate reported a vastly different bill 

(S.1630) at the end of 1989. See S. 1630, 

as reported (Dec. 20, 1989), 1990 CAA 

Legis. Hist. at 7906. As reported and 

eventually passed, S. 1630 did not 

contain the text in the House 

amendment (‘‘or emitted from a source 

category which is regulated under 

section 112’’) and instead contained the 

substitution of cross references 

(changing ‘‘section 112(b)(1)(A)’’ to 

‘‘section 112(b)’’). See S. 1630, as 

reported, 101st Cong. § 305, 1990 CAA 

Legis. Hist. at 8153; S. 1630, as passed, 

§ 305 (Apr. 3, 1990), 1990 CAA Legis. 

Hist. at 4534. Though the EPA is not 

aware of any statements in the 

legislative history that expressly explain 

the Senate’s intent in making these 

changes to the Senate bill, the sequence 

itself supports the conclusion that the 

Senate’s substitution reflects a decision 

to retain the pre-1990 approach of using 

a cross-reference to 112(b) to define the 

scope of the Section 112 Exclusion. 

Whether the difference in approach 

between the final Senate amendment in 

S.1630 and the House amendment in 

H.R. 3030 creates a substantive 

difference or are simply two different 

means of achieving the same end 

depends on what interpretation one 

gives to the text in the House 

amendment, which we turn to next. 

4. The House Amendment 

a. The House amendment is 

ambiguous. Before looking at the 

specific text of the House amendment, 

it is helpful to review some principles 

of statutory interpretation. First, 

statutory interpretation begins with the 

text, but does not end there. As the D.C. 

Circuit Court has explained, ‘‘[t]he 

literal language of a provision taken out 

of context cannot provide conclusive 

proof of congressional intent.’’ Bell 

Atlantic Telephone Cos. v. F.C.C., 131 

F.3d 1044, 1047 (D.C. Cir. 1977). See 

King v. Burwell, 2015 U.S. LEXIS 4248, 

*19(‘‘[O]ftentimes the ‘meaning—or 

ambiguity—of certain words or phrases 

may only become evident when placed 

in context.’ Brown & Williamson, 529 U. 

S., at 132, 120 S. Ct. 1291, 146 L. Ed. 

2d 121. So when deciding whether the 

language is plain, we must read the 

words ‘in their context and with a view 

to their place in the overall statutory 

scheme.’ Id., at 133, 120 S. Ct. 1291, 146 

L. Ed. 2d 121 (internal quotation marks 

omitted). Our duty, after all, is ‘to 

construe statutes, not isolated 

provisions.’ Graham County Soil and 


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Water Conservation Dist. v. United 

States ex rel. Wilson, 559 U. S. 280, 290, 

130 S. Ct. 1396, 176 L. Ed. 2d 225 (2010) 

(internal quotation marks omitted).’’). In 

addition, statutes should not be given a 

‘‘hyperliteral’’ reading that is contrary to 

established canons of statutory 

construction and common sense. See 

RadLAX Gateway Hotel v. 

Amalgamated Bank, 132 S.Ct. 2065, 

2070–71 (2012). 

Further, a proper reading of statutory 

text ‘‘must employ all the tools of 

statutory interpretation, including text, 

structure, purpose, and legislative 

history.’’ Loving v. I.R.S., 742 F.3d 1013, 

1016 (D.C. Cir. 2014) (internal quotation 

omitted). See, also, Robinson v. Shell 

Oil Co., 519 U.S. 337, 341 (1997) 

(statutory interpretation involves 

consideration of ‘‘the language itself, the 

specific context in which that language 

is used, and the broader context of the 

statute as a whole.’’). Moreover, one 

principle of statutory construction that 

has particular application here is that 

provisions in a statute should be read to 

be consistent, rather than conflicting, if 

possible. This principle was discussed 

in the recent case of Scialabba v. Cuellar 

De Osorio, 134 S. Ct. 2191, 2214 

(concurring opinion by Chief Justice 

Roberts and Justice Scalia), 2219–2220 

(dissent by Justices Sotomayor, Breyer 

and Thomas)(2014). As Justice 

Sotomayor wrote (at 134 S. Ct. at 2220): 

‘‘We do not lightly presume that Congress 

has legislated in 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 co-existence, it is the duty of 

the courts . . . to regard each as effective’’). 

In reviewing an agency’s construction of a 

statute, courts ‘‘must,’’ we have emphasized, 

‘‘interpret the statute ‘as a . . . coherent 

regulatory scheme’ ’’ rather than an internally 

inconsistent muddle, at war with itself and 

defective from the day it was written. Brown 

& Williamson, 529 U.S., at 133, 120 S. Ct. 

1291, 146 L. Ed. 2d 121. 

As amended by the House, CAA 

section 111(d)(1)(A)(i) limits CAA 

section 111(d) to any air pollutant ‘‘for 

which air quality criteria have not been 

issued or which is not included on a list 

published under section 7408(a) of this 

title or emitted from a source category 

which is regulated under section 7412 

of this title . . .’’ This statutory text is 

ambiguous and subject to numerous 

possible readings. 

First, the text of the House-amended 

version of CAA section 111(d) could be 

read literally as authorizing the 

regulation of any pollutant that is not a 

criteria pollutant. This reading arises if 

one focuses on the use of ‘‘or’’ to join 

the three clauses: 

The Administrator shall prescribe 

regulations . . . under which each State shall 

submit to the Administrator a plan which 

establishes standards of performance for any 

existing source for any air pollutant [1] for 

which air quality criteria have not been 

issued or [2] which is not included on a list 

published under section 7408(a) of this title 

or [3] emitted from a source category which 

is regulated under section 7412 of this 

title. . . . 

42 U.S.C. 7411(d)(1) (emphasis and 

internal numbering added). Because the 

text contains the conjunction ‘‘or’’ 

rather than ‘‘and’’ between the three 

clauses, a literal reading could read the 

three clauses as alternatives, rather than 

requirements to be imposed 

simultaneously. In other words, a literal 

reading of the language of section 111(d) 

provides that the Administrator may 

require states to establish standards for 

an air pollutant so long as either air 

quality criteria have not been 

established for that pollutant, or one of 

the remaining criteria is met. If this 

reading were applied to determine 

whether the EPA may promulgate CAA 

section 111(d) regulations for CO2 from 

power plants, the result would be that 

CO2 from power plants could be 

regulated under CAA section 111(b) 

because air quality criteria have not 

been issued for CO2 and therefore 

whether CO2 or power plants are 

regulated under CAA section 112 would 

be irrelevant. This reading, however, is 

not a reasonable reading of the statute 

because, among other reasons, it gives 

little or no meaning to the limitation 

covering HAP that are regulated under 

CAA section 112 and thus is contrary to 

both the CAA’s comprehensive scheme 

created by the three sets of provisions 

(under which CAA section 111 is not 

intended to duplicate the regulation of 

pollutants regulated under section 112) 

and the principle of statutory 

construction that text should not be 

construed such that a provision does not 

have effect. 

A second reading of CAA section 

111(d) as revised by the House 

amendment focuses on the lack of a 

negative before the third clause. That is, 

unlike the first and second clauses that 

each contain negative phrases (either 

‘‘has not been issued’’ or ‘‘which is not 

included’’), the third clause does not. 

One could presume that the negative 

from the second clause was intended to 

carry over, implicitly inserting another 

‘‘which is not’’ before ‘‘emitted from a 

source category which is regulated 

under section [112].’’ But that is a 

presumption, and not the plain language 

of the statute. The text as amended by 

the House says that the EPA ‘‘shall’’ 

prescribe regulations for ‘‘any air 

pollutant . . . emitted from a source 

category which is regulated under 

section [112].’’ 42 U.S.C. 7411(d)(1). 

Thus, CAA section 111(d)(1)(A)(i) could 

be read as providing for the regulation 

of emissions of pollutants if they are 

emitted from a source category that is 

regulated under CAA section 112. Like 

the first reading discussed above, this 

reading would authorize the regulation 

of CO2 emissions from existing power 

plants under CAA section 111(d). But, 

this second reading is not reasonable 

because it would provide for the 

regulation of a source’s HAP emissions 

under CAA section 111(d) when those 

same emissions were also subject to 

standards under CAA section 112. Thus, 

this reading would be contrary to 

Congress’s intent that CAA section 

111(d) regulation fill the gap between 

the other programs by covering 

pollutants that the other programs do 

not, but not duplicate the regulation of 

pollutants that the other programs 

cover. 

If one does presume that the ‘‘which 

is not’’ phrase is intended to carry over 

to the third clause, then CAA section 

111(d) regulation under the House 

amendment would be limited to ‘‘any 

air pollutant . . . which is not . . . 

emitted from a source category which is 

regulated under section [112].’’ Even 

with this presumption, however, the 

House amendment contains further 

ambiguities with respect to the phrases 

‘‘a source category’’ and ‘‘regulated 

under section 112,’’ and how those 

phrases are used within the structure of 

the provision limiting what air 

pollutants may be regulated under CAA 

section 111(d). 

The phrase ‘‘regulated under section 

112’’ is ambiguous. As the Supreme 

Court has explained in the context of 

other statutes using a variation of the 

word ‘‘regulate,’’ an agency must 

consider what is being regulated. See 

Rush Prudential HMO, Inc. v. Moran, 

536 U.S. 355, 366 (2002) (It is necessary 

to ‘‘pars[e] . . . the ‘what’ ’’ of the term 

‘‘regulates.’’); UNUM Life Ins. Co. of Am. 

v. Ward, 526 U.S. 358, 363 (1999) (the 

term ‘‘ ‘regulates insurance’ . . . 

requires interpretation, for [its] meaning 

is not plain.’’). Here, one possible 

reading is that the phase modifies the 

words ‘‘a source category’’ without 


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290 ‘‘A source category’’ could also be interpreted 

to mean ‘‘any source category.’’ Under this 

interpretation, CAA 111(d) regulation would be 

limited to air pollutants that are not emitted by any 

source category for which the EPA has issued 

standards for HAP under CAA section 112. This 

interpretation is not reasonable because it would 

effectively read CAA 111(d) out of the statute. 

Given the extensive list of source categories 

regulated under CAA 112 and the breadth of 

pollutants emitted by those categories collectively, 

literally all air pollutants would be barred from 

CAA 111(d) regulation under this interpretation. 

291 In assessing any interpretation of section 

111(d), EPA must consider how the three main 

programs set forth in the CAA work together. See 

UARG, 134 S. Ct. at 2442 (a ‘‘reasonable statutory 

interpretation must account for . . . the broader 

context of the statute as a whole’’) (quotation 

omitted). 

292Supporters of this interpretation have noted 

that the EPA could regulate power plants under 

both CAA section 111(d) and CAA section 112 if it 

regulated under section 111(d) first, before the 

Section 112 Exclusion is triggered. But that 

argument actually further demonstrates another 

reason why this interpretation is unreasonable. 

There is no basis for concluding that Congress 

intended to mandate that section 111(d) regulation 

occur first, nor is there any logical reason why the 

need to regulate under section 111(d) should be 

dependent on the timing of such regulation in 

relation to CAA 112 regulation of that source 

category. 

293Some commenters have stated that EPA could 

choose to regulate both HAP and non-HAP under 

section 111(d), and thus could regulate HAP 

without creating a gap. But this presumes that 

Congress intended EPA to have the choice of 

declining to regulate a section 112-listed source 

category for HAP under section 112, which is 

inconsistent with the mandatory language in 

section 112. See, e.g., section 112(d)(1)(‘‘The 

Administrator shall promulgate regulations 

establishing emissions standards for each category 

or subcategory of major sources and area sources of 

hazardous air pollutants listed for regulation 

pursuant to subsection (c) of this section in 

accordance with the schedules provided in 

subsections (c) and (e) of this section.’’). Moreover, 

given the prescriptive language that Congress added 

into section 112 concerning how to set standards for 

HAP, see section 112(d)(2) and (d)(3), it is 

unreasonable to conclude that Congress intended 

that the EPA could simply choose to ignore the 

provisions in section 112 and instead regulate HAP 

for a section 112 listed source category under 

section 111(d). 

Further, some supporters of this interpretation 

have suggested that EPA could regulate CO2 under 

section 112. But this suggestion fails to consider 

that sources emitting HAP are major sources if they 

emit 10 tons of any HAP. See CAA section 

112(a)(1). Thus, if CO2 were regulated as a HAP, 

and because emissions of CO2 tend to be many 

times greater than emissions of other pollutants, a 

huge number of smaller sources would become 

regulated for the first time under the CAA. 

294Even if one were to determine that this 

interpretation were the proper reading of the House 

amendment that would not be the end of the 

analysis. Instead, that reading would create a 

conflict between the Senate amendment and the 

House amendment that would need to be resolved. 

In that event, the proper resolution of a conflict 

between the two amendments would be the analysis 

and conclusion discussed in the Proposed Rule’s 

legal memorandum (discussing EPA’s analysis in 

the CAMR rule at 70 FR 15994, 16029–32): The two 

amendments must be read together so as to give 

some effect to each amendment and they are 

properly read together to provide that, where a 

source category is regulated under section 112, the 

EPA may not establish regulations covering the 

HAP emissions from that source category under 

section 111(d). 

regard to what pollutants are regulated 

under section 112, which then presents 

the issue of what meaning to give to the 

phrase ‘‘a source category.’’ 

Under this reading, and assuming the 

phrase ‘‘a source category’’ is read to 

mean the particular source category, the 

House amendment would preclude the 

regulation under CAA section 111(d) of 

a specific source category for any 

pollutant if that source category has 

been regulated for any HAP under CAA 

section 112.290 The effect of this reading 

would be to preclude the regulation of 

CO2 from power plants under CAA 

section 111(d) because power plants 

have been regulated for HAP under CAA 

section 112. This is the interpretation 

that the EPA applied to the House 

amendment in connection with the 

CAMR rule in 2005, when looking at the 

question of whether HAP can be 

regulated under CAA section 111(d) for 

a source category that is not regulated 

for HAP under section 112, and some 

commenters have advocated for this 

interpretation here. But, after 

considering all of the comments and 

reconsidering this interpretation, the 

EPA has concluded that this 

interpretation of the House amendment 

is not a reasonable reading because it 

would disrupt the comprehensive 

scheme for regulating existing sources 

created by the three sets of provisions 

covering criteria pollutants, HAP and 

the other pollutants that fall outside of 

those two programs and frustrate the 

role that section 111 is intended to 

play.291 Specifically, under this 

interpretation, the EPA could not 

regulate a source category’s emissions of 

HAP under CAA section 112, and then 

promulgate regulations for other 

pollutants from that source category 

under CAA section 111(d).292 There is 

no reason to conclude that the House 

amendment was intended to abandon 

the existing structure and relationship 

between the three programs in this way. 

Indeed, Congress expressly provided 

that regulation under CAA section 112 

was not to ‘‘diminish or replace the 

requirements of’’ the EPA’s regulation of 

non-hazardous pollutants under section 

7411. See 42 U.S.C. 7412(d)(7). Further, 

consistent with CAA section 112’s 

direction that EPA list ‘‘all categories 

and subcategories of major sources and 

area [aka, non-major] sources’’ of HAP 

and then establish CAA section 112 

standards for those categories and 

subcategories, 42 U.S.C. 7412(c)(1) and 

(c)(2), the EPA has listed and regulated 

over 140 categories of sources under 

CAA section 112. Thus, this reading 

would eviscerate the EPA’s authority 

under section 111(d) and prevent it from 

serving as the gap-filling provision 

within the comprehensive scheme of the 

CAA as Congress intended.293 In short, 

it is not reasonable to interpret the 

Section 112 Exclusion in section 111(d) 

to mean that the existence of CAA 

section 112 standards covering 

hazardous pollutants from a source 

category would entirely eliminate 

regulation of non-hazardous emissions 

from that source category under section 

111(d).294

b. The EPA’s Interpretation of the 

House Amendment. Having concluded 

that the interpretations discussed above 

are not reasonable, the EPA now turns 

to what it has concluded is the best, and 

sole reasonable, interpretation of the 

House amendment as it applies to the 

issue here. 

The EPA’s interpretation of the House 

amendment as applied to the issue 

presented in this rule is that the Section 

112 Exclusion excludes the regulation of 

HAP under CAA section 112 if the 

source category at issue is regulated 

under CAA section 112, but does not 

exclude the regulation of other 

pollutants, regardless of whether that 

source category is subject to CAA 

section 112 standards. This 

interpretation reads the phrase 

‘‘regulated under section 112’’ as 

modifying the words ‘‘source category’’ 

(as does the interpretation discussed 

above) but also recognizes that the 

phrase ‘‘regulated under section 112’’ 

refers only to the regulation of HAP 

emissions. In other words, the EPA’s 

interpretation recognizes that source 

categories ‘‘regulated under section 

112’’ are not regulated by CAA section 

112 with respect to all pollutants, but 

only with respect to HAP. Thus, it is 

reasonable to interpret the House 

amendment of the Section 112 

Exclusion as only excluding the 

regulation of HAP emissions under CAA 

section 111(d) and only when that 

source category is regulated under CAA 

section 112. We note that this 

interpretation of the House amendment 

alone is the same as the 2005 CAMR 

interpretation of the two amendments 

combined: Where a source category has 

been regulated under CAA section 112, 

a CAA section 111(d) standard of 

performance cannot be established to 

address any HAP listed under CAA 

section 112(b) that may be emitted from 

that particular source category. See 70 

FR 15994, 16029–30 (March 29, 2005). 


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295See S. Rep. No. 101–228 at 133 (‘‘There is now 

a broad consensus that the program to regulate 

hazardous air pollutants . . . should be 

restructured to provide the EPA with authority to 

regulate industrial and area sources of air pollution 

. . . in the near term’’), reprinted in 5 A Legislative 

History of the Clean Air Act Amendments of 1990 

(‘‘Legis. Hist.’’) 8338, 8473 (Comm. Print 1993); S. 

Rep. No. 101–228 at 14 (‘‘The bill gives significant 

authority to the Administrator in order to overcome 

the deficiencies in [the NAAQS program]’’) & 123 

(‘‘Experience with the mobile source provisions in 

Title II of the Act has shown that the enforcement 

authorities . . . need to be strengthened and 

broadened . . .’’), reprinted in 5 Legis. Hist. at 8354, 

8463; H.R. Rep. No. 101–952 at 336–36, 340, 345 

& 347 (discussing enhancements to Act’s motor 

vehicle provisions, the EPA’s new authority to 

promulgate chemical accident prevention 

regulations, the enactment of the Title V permit 

program, and enhancements to the EPA’s 

enforcement authority), reprinted in 5 Legis. Hist. 

at 1786, 1790, 1795, & 1997. 

296 In the past, the EPA has issued standards of 

performance under section 111(b) and emission 

guidelines under section 111(d) simultaneously. 

See ‘‘Standards of Performance for new Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills—Final 

Rule,’’ 61 FR 9905 (March 12, 1996). 

There are a number of reasons why 

the EPA’s interpretation is reasonable 

and avoids the issues discussed above. 

First, the EPA’s interpretation reads 

the House amendment to the Section 

112 Exclusion as determining the scope 

of what air pollutants are to be regulated 

under CAA section 111(d), as opposed 

to creating a wholesale exclusion for 

source categories. The other text in 

subsections 111(d)(1)(A)(i) and (ii) 

modify the phrase ‘‘any air pollutant.’’ 

Thus, reading the Section 112 Exclusion 

to also address the question of what air 

pollutants may be regulated under CAA 

section 111(d) is consistent with the 

overall structure and focus of CAA 

section 111(d)(1)(A). 

Second, the EPA’s interpretation 

furthers—rather than undermines—the 

purpose of CAA section 111(d) within 

the long-standing structure of the CAA. 

That is, this interpretation supports the 

comprehensive structure for regulating 

various pollutants from existing sources 

under the criteria pollutant/NAAQS 

program under sections 108–110, the 

HAP program under section 112, and 

other pollutants under section 111(d), 

and avoids creating a gap in that 

structure. See King v. Burwell, 2015 U.S. 

LEXIS 4248, *28 (2015)(‘‘A provision 

that may seem ambiguous in isolation is 

often clarified by the remainder of the 

statutory scheme . . . because only one 

of the permissible meanings produces a 

substantive effect that is compatible 

with the rest of the law.’’) (quoting 

United Sav. Assn. of Tex. v. Timbers of 

Inwood Forest Associates, Ltd., 484 U. 

S. 365, 371, 108 S. Ct. 626, 98 L. Ed. 2d 

740 (1988)’’) 

Third, by avoiding the creation of 

gaps in the statutory structure, the 

EPA’s interpretation is consistent with 

the legislative history demonstrating 

that Congress’s intent in the 1990 CAA 

Amendments was to expand the EPA’s 

regulatory authority across the board, 

compelling the agency to regulate more 

pollutants, under more programs, more 

quickly.295 Conversely, the EPA is 

aware of no statement in the legislative 

history indicating that Congress 

simultaneously sought to restrict the 

EPA’s authority under CAA section 

111(d) or to create gaps in the 

comprehensive structure of the statute. 

If Congress had intended this 

amendment to make such a change, one 

would expect to see some indication of 

that in the legislative history. 

Fourth, when applied in the context 

of this rule, the EPA’s interpretation of 

the House amendment is consistent 

with the Senate amendment. Thus, this 

interpretation avoids creating a conflict 

within the statute. See discussion above 

of Scialabba v. Cuellar De Osorio, 134 

S. Ct. 2191 at 2220 (citing and quoting, 

among other authorities, A. Scalia & B. 

Garner, Reading Law: The Interpretation 

of Legal Texts 180 (2012) (‘‘The 

provisions of a text should be 

interpreted in a way that renders them 

compatible, not contradictory. . . . 

[T]here can be no justification for 

needlessly rendering provisions in 

conflict if they can be interpreted 

harmoniously’’)). 

In sum, when this interpretation of 

the House amendment is applied in the 

context of this rule, the result is that the 

EPA may promulgate CAA section 

111(d) regulations covering carbon 

dioxide emissions from existing power 

plants notwithstanding that power 

plants are regulated for their HAP 

emissions under CAA section 112. 

5. The Two Amendments Are Easily 

Reconciled and Can Be Given Full Effect 

Given that both the House and Senate 

amendments should be read 

individually as having the same 

meaning in the context presented in this 

rule, giving each amendment full effect 

is straight-forward: The Section 112 

Exclusion in section 111(d) does not 

foreclose the regulation of non-HAP 

from a source category regardless of 

whether that source category is also 

regulated under CAA section 112. As 

applied here, the EPA has the authority 

to promulgate CAA section 111(d) 

regulations for CO2 from power plants 

notwithstanding that power plants are 

regulated for HAP under CAA section 

112. 

C. Authority To Regulate EGUs 

In a separate, concurrent action, the 

EPA is also finalizing a CAA section 

111(b) rulemaking that regulates CO2

emissions from new, modified, and 

reconstructed EGUs. The promulgation 

of these standards provides the requisite 

predicate for applicability of CAA 

section 111(d). 

CAA section 111(d)(1) requires the 

EPA to promulgate regulations under 

which states must submit state plans 

regulating ‘‘any existing source’’ of 

certain pollutants ‘‘to which a standard 

of performance would apply if such 

existing source were a new source.’’ A 

‘‘new source’’ is ‘‘any stationary source, 

the construction or modification of 

which is commenced after the 

publication of regulations (or, if earlier, 

proposed regulations) prescribing a 

standard of performance under [CAA 

section 111] which will be applicable to 

such source.’’ It should be noted that 

these provisions make clear that a ‘‘new 

source’’ includes one that undertakes 

either new construction or a 

modification. It should also be noted 

that the EPA’s implementing regulations 

define ‘‘construction’’ to include 

‘‘reconstruction,’’ which the 

implementing regulations go on to 

define as the replacement of 

components of an existing facility to an 

extent that (i) the fixed capital cost of 

the new components exceeds 50 percent 

of the fixed capital cost that would be 

required to construct a comparable 

entirely new facility, and (ii) it is 

technologically and economically 

feasible to meet the applicable 

standards. 

Under CAA section 111(d)(1), in order 

for existing sources to become subject to 

that provision, the EPA must 

promulgate standards of performance 

under CAA section 111(b) to which, if 

the existing sources were new sources, 

they would be subject. Those standards 

of performance may include standards 

for sources that undertake new 

construction, modifications, or 

reconstructions. 

The EPA is finalizing a rulemaking 

under CAA section 111(b) for CO2

emissions from affected EGUs 

concurrently with this CAA section 

111(d) rulemaking, which will provide 

the requisite predicate for applicability 

of CAA section 111(d).296

D. Definition of Affected Sources 

For the emission guidelines, an 

affected EGU is any fossil fuel-fired 

electric utility steam generating unit 

(i.e., utility boiler or integrated 

gasification combined cycle (IGCC) unit) 

or stationary combustion turbine that 

was in operation or had commenced 


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297Under 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). 

construction as of January 8, 2014,297

and that meets the following criteria, 

which differ depending on the type of 

unit. To be an affected EGU, such a unit, 

if it is a fossil fuel-fired electric utility 

steam generating unit (i.e., a utility 

boiler or IGCC unit), must serve a 

generator capable of selling greater than 

25 MW to a utility power distribution 

system and have a base load rating 

greater than 260 GJ/h (250 MMBtu/h) 

heat input of fossil fuel (either alone or 

in combination with any other fuel). If 

such a unit is a stationary combustion 

turbine, the unit must meet the 

definition of a combined cycle or 

combined heat and power combustion 

turbine, serve a generator capable of 

selling greater than 25 MW to a utility 

power distribution system, and have a 

base load rating of greater than 260 

GJ/h (250 MMBtu/h). 

When considering and understanding 

applicability, the following definitions 

may be helpful. Simple cycle 

combustion turbine means any 

stationary combustion turbine which 

does not recover heat from the 

combustion turbine engine exhaust 

gases for purposes other than enhancing 

the performance of the stationary 

combustion turbine itself. Combined 

cycle combustion turbine means any 

stationary combustion turbine which 

recovers heat from the combustion 

turbine engine exhaust gases to generate 

steam that is used to create additional 

electric power output in a steam 

turbine. Combined heat and power 

(CHP) combustion turbine means any 

stationary combustion turbine which 

recovers heat from the combustion 

turbine engine exhaust gases to heat 

water or another medium, generate 

steam for useful purposes other than 

exclusively for additional electric 

generation, or directly uses the heat in 

the exhaust gases for a useful purpose. 

We note that certain affected EGUs are 

exempt from inclusion in a state plan. 

Affected EGUs that may be excluded 

from a state’s plan are (1) those units 

that are subject to subpart TTTT as a 

result of commencing modification or 

reconstruction; (2) steam generating 

units or IGCC units that are currently 

and always have been subject to a 

federally enforceable permit limiting 

net-electric sales to one-third or less of 

its potential electric output or 219,000 

MWh or less on an annual basis; (3) 

non-fossil units (i.e., units that are 

capable of combusting 50 percent or 

more non-fossil fuel) that have 

historically limited the use of fossil 

fuels to 10 percent or less of the annual 

capacity factor or are subject to a 

federally enforceable permit limiting 

fossil fuel use to 10 percent or less of 

the annual capacity factor; (4) stationary 

combustion turbines that are not 

capable of combusting natural gas (i.e., 

not connected to a natural gas pipeline); 

(5) combined heat and power units that 

are subject to a federally enforceable 

permit limiting, or have historically 

limited, annual net electric sales to a 

utility power distribution system to the 

product of the design efficiency and the 

potential electric output or 219,000 

MWh (whichever is greater) or less; (6) 

units that serve a generator along with 

other steam generating unit(s), IGCC(s), 

or stationary combustion turbine(s) 

where the effective generation capacity 

(determined based on a prorated output 

of the base load rating of each steam 

generating unit, IGCC, or stationary 

combustion turbine) is 25 MW or less; 

(7) municipal waste combustor unit 

subject to subpart Eb of Part 60; or (8) 

commercial or industrial solid waste 

incineration units that are subject to 

subpart CCCC of Part 60. 

The rationale for applicability of this 

final rule is multi-fold. We had 

proposed that affected EGUs were those 

existing fossil fuel-fired EGUs that met 

the applicability criteria for coverage 

under the final GHG standards for new 

fossil fuel-fired EGUs being 

promulgated under section 111(b). 

However, we are finalizing that States 

need not include certain units that 

would otherwise meet the CAA section 

111(b) applicability in this CAA section 

111(d) emission guidelines. These 

include simple cycle turbines, certain 

non-fossil units, and certain combined 

heat and power units. The final 111(b) 

standards include applicability criteria 

for simple cycle combustion turbines, 

for reasons relating to implementation 

and minimizing emissions from all 

future combustion turbines. However, 

for the following reasons none of the 

building blocks would result in 

emission reductions from simple cycle 

turbines so we are not requiring that 

States including them in their CAA 

section 111(d) plans. 

First, even more than combined cycle 

units, simple cycle units have limited 

opportunities, compared to steam 

generating units, to reduce their heat 

rate. Most combustion turbines likely 

already follow the manufacturer’s 

recommended regular preventive/

restorative maintenance for both reliable 

and efficiency reasons. These regularly 

scheduled maintenance practices are 

highly effective methods to maintain 

heat rates, and additional fleet-wide 

reductions from simple cycle 

combustion turbines are likely less than 

2 percent. In addition, while 

approximately one-fifth of overall fossil 

fuel-fired capacity (GW) consists of 

simple cycle turbines, these units 

historically have operated at capacity 

factors of less than 5 percent and only 

provide about 1 percent of the fossil 

fuel-fired generation (GWh). 

Combustion turbine capacity can 

therefore only contribute CO2 emissions 

amounting to approximately 2 percent 

of total coal-steam CO2 emissions. Any 

single-digit percentage reduction in 

combustion turbine heat rates would 

therefore provide less than 1 percent 

reduction in total fossil-fired CO2

emissions. 

Further, we are not aware of an 

approach to estimate any limited 

opportunities that existing simple cycle 

turbines may have to reduce their heat 

rate. Similar to coal-steam EGUs, we do 

not have the unit-specific detailed 

design information on existing 

individual simple cycle combustion 

turbines that is necessary for a detailed 

assessment of the heat rate improvement 

potential via best practices and 

upgrades for each unit. While the EPA 

could conduct a ‘‘variability analysis’’ of 

simple cycle historical hourly heat rate 

data (as was done for coal-steam EGUs), 

the various simple cycle models in use 

and the historically lower capacity 

factors of the simple cycle fleet (less run 

time per start, and more part load 

operation) would require a simple cycle 

analysis that includes more complexity 

and likely more uncertainty than in the 

coal-steam analysis. Therefore, we do 

not consider it feasible to estimate 

potential reductions due to heat rate 

improvements from simple cycle 

turbines, and even if it were, we have 

concluded those reductions would be 

negligible compared to the reductions 

from steam generating units. Hence, we 

do not consider building block 1 as 

practically applicable to simple cycle 

units. 

Second, the vast majority of simple 

cycle turbines serve a specific need— 

providing power during periods of peak 

electric demand (i.e., peaking units). 

The existing block of simple cycle 

turbines are the only units that are able 

to start fast enough and ramp to full 

load quickly enough to serve as peaking 

units. If these units were to be used 

under building block 2 to displace 

higher emitting coal-fired units, they 

would no longer be available to serve as 

peaking units. Therefore, building block 

2 could not be applied to simple cycle 


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298The EPA is not codifying any of the 

requirements of this rulemaking in subparts Da or 

KKKK. 

combustion turbines without 

jeopardizing grid reliability. 

Third, many commenters on the CAA 

section 111(b) proposal stated that 

simple cycle turbines will be used to 

provide backup power to intermittent 

renewable sources of power such as 

wind and solar. Consequently, adding 

additional generation from intermittent 

renewable sources has the potential to 

actually increase emissions from simple 

cycle turbines. Therefore, applying 

building block 3 based on the capacity 

of simple cycle turbines would not 

result in emission reductions from 

simple cycle combustion turbines. 

Finally, the EPA expects existing simple 

cycle turbines to continue to operate as 

they historically have operated, as 

peaking units. Including simple cycle 

turbines in CAA section 111(d) 

applicability would impact the 

numerical value of state goals, but it 

would not impact the stringency of the 

plans. Such inclusion would increase 

burden but result in no environmental 

benefit. 

Additionally, under CAA section 

111(b) final applicability criteria, new 

dedicated non-fossil and industrial CHP 

units are not affected sources if they 

include permit restrictions on the 

amount of fossil fuel they burn and the 

amount of electricity they sell. Such 

units historically have had no regulatory 

mandate to include permit requirements 

limiting the use of fossil fuel or electric 

sales. We are exempting them from 

inclusion in CAA section 111(d) state 

plans in the interest of consistency with 

CAA section 111(b) and based on their 

historical fuel use and electric sales. 

We discuss changes in applicability of 

units in relation to state plans in Section 

VIII of this preamble. 

E. Combined Categories and 

Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is 

combining the listing of sources from 

the two existing source categories for 

the affected EGUs, as listed in 40 CFR 

subpart Da and 40 CFR subpart KKKK, 

into a single location, 40 CFR subpart 

UUUU, for purposes of addressing the 

CO2 emissions from existing affected 

EGUs. The EPA is also codifying all of 

the requirements for the affected EGUs 

in a new subpart UUUU of 40 CFR part 

60 and including all GHG emission 

guidelines for the affected sources— 

fossil fuel–fired electric utility steam 

generating units, as well as stationary 

combustion turbines—in that newly 

created subpart.298

We believe that combining the 

emission guidelines for affected sources 

into a new subpart UUUU is appropriate 

because the emission guidelines the 

EPA is establishing do not vary by type 

of source. Combining the listing of 

sources into one location, subpart 

UUUU, will facilitate implementation of 

CO2 mitigation measures, such as 

shifting generation from higher to lowercarbon intensity generation among 

existing sources (e.g., shifting from 

utility boilers to NGCC units), and 

emission trading among sources in the 

source category. 

As discussed in the January 8, 2014 

proposal for the CAA section 111(b) 

standards for GHG emissions from EGUs 

(79 FR 1430), in 1971 the EPA listed 

fossil fuel-fired steam generating boilers 

as a new category subject to section 111 

rulemaking, and in 1979 the EPA listed 

fossil fuel-fired combustion turbines as 

a new category subject to the CAA 

section 111 rulemaking. In the ensuing 

years, the EPA has promulgated 

standards of performance for the two 

categories and codified those standards, 

at various times, in 40 CFR part 60 

subparts D, Da, GG, and KKKK. 

In the January 8, 2014 proposal, the 

EPA proposed separate standards of 

performance for new sources in the two 

categories 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 coproposed combining the two categories 

into a single category solely for 

purposes of the CO2 emissions from new 

construction of affected EGUs, and 

codifying the proposed requirements in 

a new 40 CFR part 60 subpart TTTT. For 

the final standards of performance for 

new construction of affected EGUs, the 

EPA is codifying the final requirements 

in a new 40 CFR part 60 subpart TTTT. 

In this rulemaking, the EPA is 

combining the two listed source 

categories into a single source category 

for purposes of the emission guidelines 

for the CO2 emissions from existing 

affected EGUs. Because the two source 

categories are pre-existing and the EPA 

would not be subjecting any additional 

sources to regulation, the combined 

source category is not considered a new 

source category that the EPA must list 

under CAA section 111(b)(1)(A). As a 

result, this final rule does not list a new 

source category under section 

111(a)(1)(A), nor does this final rule 

revise either of the two source 

categories—fossil fuel—fired electric 

utility steam generating units and 

stationary combustion turbines—that 

the EPA has already listed under that 

provision. Thus, the EPA is not required 

to make a finding that the combined 

source category causes or contributes 

significantly 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 EE to reduce 

the amount of fossil fuel-fired 

generation—which we categorized as 

four ‘‘building blocks.’’ As an 

alternative to the proposed building 

blocks 2, 3, and 4, the EPA also 

identified reduced generation in the 

amount of those building blocks as part 

of the BSER. These measures are not the 

only approaches EGUs can take to 

reduce CO2, but are those that the EPA 

felt best met the statutory criteria. We 

solicited comment on all aspects of our 

BSER determination, including a broad 

array of other approaches. We have 

considered thoroughly the extensive 

comments submitted on a variety of 

topics related to the BSER and the 

individual building blocks, along with 

our own continued analysis, and we are 

finalizing the BSER based on the first 

three building blocks, with certain 

refinements. 

Consistent with the approach taken in 

the proposed rule, in determining the 

BSER we have taken account of the 

unique characteristics of CO2 pollution, 

particularly its global nature, huge 

quantities, and the limited means for 

controlling it; and the unique 

characteristics of the source category, 

particularly the exceptional degree of 

interconnectedness among individual 

affected EGUs and the longstanding 

practice of coordinating planning and 

operations across multiple sources, 

reflecting the fact that each EGU’s 

function is interdependent with the 

function of other EGUs. Each building 


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

300We also discuss our interpretation of the 

requirements for standards of performance and the 

BSER under section 111(b), for new sources, in the 

section 111(b) rulemaking that the EPA is finalizing 

simultaneously with this rule and in the Legal 

Memorandum for this rule. Our interpretations of 

block is a proven approach for reducing 

emissions from the affected source 

category that is appropriate in this 

pollutant- and industry-specific context. 

The BSER also encompasses a variety of 

measures or actions that individual 

affected EGUs could take to implement 

the building blocks, including (i) direct 

investment in efficiency improvements 

and in lower- and zero-carbon 

generation, (ii) cross-investment in these 

activities through mechanisms such as 

emissions trading approaches, where 

the state-established standards of 

performance to which sources are 

subject incorporate such approaches, 

and (iii) reduction of higher-carbon 

generation. 

With attention to emission reduction 

costs, electricity rates, and the 

importance of ensuring continued 

reliability of electricity supplies, the 

individual building blocks and the 

overall BSER have been defined not at 

the maximum possible degree of 

stringency but at a reasonable degree of 

stringency designed to appropriately 

balance consideration of the various 

BSER factors. Additional, non-building 

block-specific aspects of the BSER 

quantification methodology discussed 

below are similarly mindful of these 

considerations. This approach to 

determination of the BSER provides 

compliance headroom that ensures that 

the emission limitations reflecting the 

BSER are achievable by the source 

category, but nevertheless, as required 

by the CAA, will result in meaningful 

reductions in CO2 emissions from this 

sector. The wide range of actions 

encompassed in the building blocks, 

and a further wide range of possible 

emissions-reducing actions not included 

in the BSER but nevertheless available 

to help with compliance, ensure that 

those emission limitations are 

achievable by individual affected EGUs 

as well. 

The final BSER incorporates certain 

changes from the proposed rule, 

reflecting the EPA’s consideration of 

comments responding to the approaches 

outlined in the proposal and our own 

further analysis. The principal changes 

are the exclusion from the BSER of 

emission reductions achievable through 

demand-side EE and through nuclear 

generation; a revised approach to 

determination of emission reductions 

achievable through increased RE 

generation; a consistent approach to 

determination of emission reductions 

achievable through all the building 

blocks that better reflects the regional 

nature of the electricity system and 

entails separate analyses for the Eastern, 

Western, and Texas Interconnections; 

and a revised interim goal period of 

2022 to 2029 (instead of the proposed 

interim period of 2020 to 2029). These 

changes to the BSER and the building 

blocks are discussed in more detail later 

in this section of the preamble. 

Also, to address concerns identified 

in the proposal and the October 30, 

2014 NODA and in response to 

associated comments, in the final rule 

we have represented the emission 

limitations achievable through the BSER 

in the form of uniform CO2 emission 

performance rates for each of two 

affected source subcategories: Steam 

generating units and stationary 

combustion turbines. However, like the 

proposed rule, the final rule also 

provides weighted-average state-specific 

goals that a state may choose as an 

alternative method for complying with 

its obligation to set standards of 

performance for its affected EGUs—an 

alternative, that is, to adopting the 

nationwide subcategory-based CO2

emission performance rates as the 

standard of performance for its affected 

EGUs. The reformulation of the 

emission limitations as uniform CO2

emission performance rates is discussed 

in this section and in section VI of the 

preamble, and the relation of the 

performance rates to the state-specific 

goals and states’ section 111(d) plan 

options is discussed in sections VII and 

VIII of the preamble. 

Section V.A. describes our 

determination of the final BSER, 

including a discussion of the associated 

emissions performance level, and 

provides the rationale for our 

determination. In section V.B. we 

address certain legal issues in greater 

detail, including key issues raised in 

comments. Sections V.C. through V.E. 

contain more detailed discussions of the 

three individual building blocks 

included in the final BSER. Further 

information can be found in the GHG 

Mitigation Measures TSD for the CPP 

Final Rule, the CO2 Emission 

Performance Rate and Goal 

Computation TSD for the CPP Final 

Rule, the Response to Comments 

document, and, about certain topics, the 

Legal Memorandum for the Clean Power 

Plan Final Rule, all of which are 

available in the docket. 

A. The Best System of Emission 

Reduction 

This section sets forth our 

determination of the BSER for reducing 

CO2 emissions from existing EGUs, 

including a discussion of the associated 

emissions performance level, and the 

rationale for that determination. In 

section V.A.1., we describe the legal 

framework for determination of the 

BSER in general. Section V.A.2. 

summarizes the determination of the 

BSER for this rule. In section V.A.3., we 

discuss changes from the proposal. 

Section V.A.4. provides more detail on 

our determination of the BSER, 

including our determinations regarding 

the individual elements of the BSER, as 

applied to the two subcategories of 

fossil steam units and combustion 

turbines. In section V.A.5., we explain 

the specific actions that individual 

affected EGUs in the two subcategories 

may take to implement the building 

blocks and thereby achieve the EPAidentified source subcategory-specific 

emission performance rates that, in turn, 

form the basis for the standards of 

performance that states must set. 

Because these actions implement the 

building blocks, they may be 

understood as part of the BSER. In this 

discussion, we recognize that states can 

choose to set sources’ standards of 

performance in different forms and that 

the form of the standard affects how 

various types of actions can be used to 

comply with the standard. In section 

V.A.6., we discuss the substantial 

compliance flexibility provided by 

additional measures, not included in the 

BSER, that individual affected EGUs can 

use to achieve their standards of 

performance. Finally, section V.A.7. 

addresses the severability of the 

building blocks. 

1. Legal Requirements for BSER in the 

Emission Guidelines 

a. Introduction. In the June 2014 

proposal for this rule, we described the 

principal legal requirements for 

standards of performance under CAA 

section 111(d)(1) and (a)(1). We based 

our 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 fuel-fired 

EGUs. In the latter proposal, we noted 

that the D.C. Circuit has handed down 

numerous decisions that interpret CAA 

section 111(a)(1), including its 

component elements, and we reviewed 

that case law in detail.299

We received comments on our 

proposed interpretation, and in light of 

those comments, in this final rule, we 

are clarifying our interpretation in 

certain respects. We discuss our 

interpretation below.300


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these requirements in the two rules are generally 

consistent except to the extent that they reflect 

distinctions between new and existing sources. For 

example, as discussed in the section 111(b) rule, the 

legislative history indicates that Congress intended 

that the BSER for new industrial facilities, which 

were expected to have lengthy useful lives, would 

include the most advanced pollution controls 

available, but Congress had a broader conception of 

the BSER for existing facilities. 

301Our interpretation of the CAA provisions at 

issue is guided by Chevron U.S.A. Inc. v. NRDC, 

467 U.S. 837, 842–43 (1984). In Chevron, the U.S. 

Supreme Court set out a two-step process for agency 

interpretation of statutory requirements: the agency 

must, at step 1, determine whether Congress’s 

intent as to the specific matter at issue is clear, and, 

if so, the agency must give effect to that intent. If 

congressional intent is not clear, then, at step 2, the 

agency has discretion to fashion an interpretation 

that is a reasonable construction of the statute. 

302 40 CFR 60.21(e). This definition was 

promulgated as part of the EPA’s CAA 111(d) 

implementing regulations and was not updated to 

reflect the textual changes adopted by Congress in 

1977. That said, Congress recognized that those 

changes ‘‘merely make[] explicit what was implicit 

in the previous language.’’ H.R. Rep. No. 95–294, 

at 190 (May 12, 1977). 

303 40 CFR 60.24(b)(3). 

304The 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 case-bycase basis for particular designated facilities, or 

classes of facilities, States may provide for the 

application of less stringent emission standards or 

longer compliance schedules than those otherwise 

required’’ by the corresponding emission guideline. 

40 CFR 60.24(f). Some of the factors that a state may 

consider for this case-by-case analysis include the 

‘‘cost of control resulting from plant age, location, 

or basic process design’’ and the ‘‘physical 

impossibility of installing necessary control 

equipment,’’ among other factors ‘‘that make 

application of a less stringent standard or final 

compliance time significantly more reasonable.’’ Id. 

305 In addition, CAA section 116 authorizes the 

state to set standards of performance for all of its 

sources that, together, are more stringent than the 

EPA’s emission guidelines. 

306 40 CFR 60.23. 

307 In the 1970 CAAA, Congress defined 

‘‘standard of performance,’’ under § 111(a)(1), as: 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of 

emission reduction which (taking into account the 

cost of achieving such reduction) the Administrator 

determines has been adequately demonstrated. 

In the 1977 CAAA, Congress revised the 

definition to distinguish among different types of 

sources, and to require that for fossil fuel-fired 

sources, the standard (i) be based on, in lieu of the 

‘‘best system of emission reduction . . . adequately 

demonstrated,’’ the ‘‘best technological system of 

continuous emission reduction . . . adequately 

demonstrated;’’ and (ii) require a percentage 

reduction in emissions. In addition, in the 1977 

CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the 

cost of achieving the reduction to also require the 

Administrator to consider ‘‘any nonair quality 

health and environmental 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 remain relevant to the 

definition as it reads today. 

308Portland 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). 

b. CAA requirements and court 

interpretation.301 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 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.302

The EPA’s approach in this 

rulemaking is to determine the BSER on 

a source subcategory-wide basis, to 

determine the emission limitation that 

results from applying the BSER to the 

sources in the subcategory, and then to 

establish emission guidelines for the 

states that incorporate those emission 

limitations. The EPA expresses these 

emission limitations in the form of 

emission performance rates, and they 

must be achievable by the source 

subcategory through the application of 

the BSER. 

Following the EPA’s promulgation of 

emission guidelines, each state must 

determine the standards of performance 

for its sources, which the EPA’s 

regulations call ‘‘designated 

facilities.’’ 303 A state has broad 

discretion in doing so. CAA section 

111(d)(1) requires the EPA’s regulations 

to ‘‘permit the State in applying a 

standard of performance to any 

particular source . . . to take into 

consideration, among other factors, the 

remaining useful life of the . . . 

source. . .’’ 304 In addition, under CAA 

section 116, the state is authorized to set 

a standard of performance for any 

particular source that is more stringent 

than the emission limit contained in the 

EPA’s emission guidelines.305 Thus, for 

any particular source, a state may apply 

a standard of performance that is either 

more stringent or less stringent than the 

performance level in the emission 

guidelines, as long as, in total, the 

state’s sources achieve at least the same 

degree of emission limitation as 

included in the EPA’s emission 

guidelines. The states must include the 

standards of performance in their state 

plans and submit the plans to the EPA 

for review.306 Under CAA section 

111(d)(2)(A), the EPA approves state 

plans as long as they are ‘‘satisfactory.’’ 

As noted in the January 2014 proposal 

and discussed in more detail above 

under section II.G, Congress first 

included the definition of ‘‘standard of 

performance’’ when enacting CAA 

section 111 in the 1970 Clean Air Act 

Amendments (CAAA), amended it in 

the 1977 CAAA, and then amended it 

again in the 1990 CAAA to largely 

restore the definition as it read in the 

1970 CAAA. It is in the legislative 

history for the 1970 and 1977 CAAA 

that Congress primarily addressed the 

definition as it read at those times and 

that legislative history provides 

guidance in interpreting this 

provision.307 In addition, although the 

D.C. Circuit has never reviewed a 

section 111(d) rulemaking, the Court has 

reviewed section 111(b) rulemakings on 

numerous occasions during the past 40 

years, handing down decisions dated 

from 1973 to 2011,308 through which the 

Court has developed a body of case law 

that interprets the term ‘‘standard of 

performance.’’ 

c. Key elements of interpretation. The 

emission guidelines promulgated by the 

Administrator must include emission 

limitations that are ‘‘achievable’’ by the 

source category by application of a 

‘‘system of emission reduction’’ that is 

‘‘adequately demonstrated’’ and that the 

EPA determines to be the ‘‘best,’’ 


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309See Sierra Club v. Costle, 657 F.2d 298, 326 

(D.C. Cir. 1981). 

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

311See Lignite Energy Council v. EPA, 198 F.3d 

930, 933 (D.C. Cir. 1999). 

312Although CAA section 111(a)(1) may be read 

to state that the factors enumerated in the 

parenthetical are part of the ‘‘adequately 

demonstrated’’ determination, the D.C. Circuit’s 

case law appears to treat them as part of the ‘‘best’’ 

determination. See Sierra Club v. Costle, 657 F.2d 

at 330 (recognizing that CAA section 111 gives the 

EPA authority ‘‘when determining the best 

technological system to weigh cost, energy, and 

environmental impacts’’). Nevertheless, it does not 

appear that those two approaches would lead to 

different outcomes. See, e.g., Lignite Energy Council 

v. EPA, 198 F.3d at 933 (rejecting challenge to the 

EPA’s cost assessment of the ‘‘best demonstrated 

system’’). In this rule, the EPA treats the factors as 

part of the ‘‘best’’ determination, but, as noted, even 

if the factors were part of the ‘‘adequately 

demonstrated’’ determination, our analysis and 

outcome would be the same. 

313See, e.g., Oil and Natural Gas Sector: New 

Source Performance Standards and National 

Emission Standards for Hazardous Air pollutants 

Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 

(describing the three-step analysis in setting a 

standard of performance). 

314Oxford Dictionary of English (3rd ed.) (2010), 

available at http://www.oxforddictionaries.com/us/ 

definition/american_english/system; see also 

American Heritage Dictionary (5th ed.) (2013), 

available at http://www.yourdictionary.com/

system#americanheritage; and The American 

College Dictionary (C.L. Barnhart, ed. 1970) (‘‘an 

assemblage or combination of things or parts 

forming a complex or unitary whole’’). 

315Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 

427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 

(1974). 

316Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted) 

(discussing the Senate and House bills and reports 

from which the language in CAA section 111 grew). 

317 Ibid. 

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

319Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 

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

321 Lignite Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999). 

322Portland Cement Ass’n v. EPA, 513 F.2d 506, 

508 (D.C. Cir. 1975). 

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

Cir. 1981). 

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

Cir. 1981). 

‘‘taking into account’’ the factors of 

‘‘cost . . . nonair quality health and 

environmental impact and energy 

requirements.’’ The D.C. Circuit has 

stated that in determining the ‘‘best’’ 

system, the EPA must also take into 

account ‘‘the amount of air 

pollution’’ 309 reduced and the role of 

‘‘technological innovation.’’ 310 The 

Court has emphasized that the EPA has 

discretion in weighing those various 

factors.311 312

Our overall approach to determining 

the BSER and emission guidelines, 

which incorporates the various 

elements, is as follows: In developing an 

emission guideline, we generally engage 

in an analytical approach that is similar 

to what we conduct under CAA section 

111(b) for new sources. First, we 

identify ‘‘system[s] of emission 

reduction’’ that have been ‘‘adequately 

demonstrated’’ for a particular source 

category. Second, we determine the 

‘‘best’’ of these systems after evaluating 

the amount of reductions, costs, any 

nonair health and environmental 

impacts, energy requirements, and, in 

the alternative, the advancement of 

technology (that is, we apply a 

formulation of the BSER with the above 

noted factors, and then, in the 

alternative, we apply a formulation of 

the BSER with those same factors plus 

the advancement of technology). And 

third, we select an achievable emission 

limit—here, the emission performance 

rates—based on the BSER.313 In contrast 

to subsection (b), however, subsection 

(d)(1) assigns to the states, not the EPA, 

the obligation of setting standards of 

performance for the affected sources. As 

discussed below in the following 

subsection, in examining the range of 

reasonable options for states to consider 

in setting standards of performance 

under these guidelines, we identified a 

number of considerations, including the 

interconnected operations of the 

affected sources and the characteristics 

of the CO2 pollutant. 

The remainder of this subsection 

discusses the various elements in our 

general analytical approach. 

(1) System of Emission Reduction 

As we discuss below, the CAA does 

not define the phrase ‘‘system of 

emission reduction.’’ The ordinary, 

everyday meaning of ‘‘system’’ is a set 

of things or parts forming a complex 

whole; a set of principles or procedures 

according to which something is done; 

an organized scheme or method; and a 

group of interacting, interrelated, or 

interdependent elements.314 With this 

definition, the phrase ‘‘system of 

emission reduction’’ takes a broad 

meaning: a set of measures that work 

together to reduce emissions. The EPA 

interprets this phrase to carry an 

important limitation: Because the 

emission guidelines for the existing 

sources must reflect ‘‘the degree of 

emission limitation achievable through 

the application of the best system of 

emission reduction . . . adequately 

demonstrated,’’ the system must be 

limited to measures that can be 

implemented—‘‘appl[ied]’’—by the 

sources themselves, that is, as a 

practical matter, by actions taken by the 

owners or operators of the sources. As 

we discuss below, this definition is 

sufficiently broad to include the 

building blocks. 

(2) ‘‘Adequately Demonstrated’’ 

Under section 111(a)(1), in order for a 

‘‘system of emission reduction’’ to serve 

as the basis for an ‘‘achievable’’ 

emission limitation, the Administrator 

must determine that the system is 

‘‘adequately demonstrated.’’ This 

means, according to the D.C. Circuit, 

that the system is ‘‘one which has been 

shown to be reasonably reliable, 

reasonably efficient, and which can 

reasonably be expected to serve the 

interests of pollution control without 

becoming exorbitantly costly in an 

economic or environmental way.’’ 315 It 

does not mean that the system ‘‘must be 

in actual routine use somewhere.’’ 316

Rather, the Court has said, ‘‘[t]he 

Administrator may make a projection 

based on existing technology, though 

that projection is subject to the 

restraints of reasonableness and cannot 

be based on ‘crystal ball’ inquiry.’’ 317

Similarly, the EPA may ‘‘hold the 

industry to a standard of improved 

design and operational advances, so 

long as there is substantial evidence that 

such improvements are feasible.’’ 318

Ultimately, the analysis ‘‘is partially 

dependent on ‘lead time,’’’ that is, ‘‘the 

time in which the technology will have 

to be available.’’ 319 Unlike for CAA 

section 111(b) standards that are 

applicable immediately after the 

effective date of their promulgation, 

under CAA section 111(e), compliance 

with CAA section 111(d) standards may 

be set sometime in the future. This is 

due, in part, to the period of time for 

states to submit state plans and for the 

EPA to act on them. 

(3) ‘‘Best’’ 

In determining which adequately 

demonstrated system of emission 

reduction is the ‘‘best,’’ the EPA 

considers the following factors: 

(a) Costs 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘the cost 

of achieving’’ the required emission 

reductions. As described in the January 

2014 proposal,320 in several cases the 

D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard 

in various ways, stating that the EPA 

may not adopt a standard the cost of 

which would be ‘‘exorbitant,’’ 321

‘‘greater than the industry could bear 

and survive,’’ 322 ‘‘excessive,’’ 323 or 

‘‘unreasonable.’’ 324 These formulations 

appear to be synonymous, and for 

convenience, in this rulemaking, we 

will use reasonableness as the standard, 


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325These 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. 

326We received comments that we do not have 

authority to revise the cost standard as established 

in the case law, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., 

to a ‘‘reasonableness’’ standard that the commenters 

considered less protective of the environment. We 

agree that we do not have authority to revise the 

cost standard as established in the case law, and we 

are not attempting to do so here. Rather, our 

description of the cost standard as ‘‘reasonableness’’ 

is intended to be a convenient term for referring to 

the cost standard as established in the case law. 

327 1977 House Committee Report at 184. 

328The costs for these standards were described 

in the rulemakings. See 36 FR 24876 (December 23, 

1971), 37 FR 5767, 5769 (March 21, 1972). 

329 Indeed, in upholding the EPA’s consideration 

of costs under other provisions requiring 

consideration of cost, courts have also noted the 

substantial discretion delegated to the EPA to weigh 

cost considerations with other factors. Chemical 

Mfr’s Ass’n v. EPA, 870 F. 2d 177, 251 (5th Cir. 

1989); Am. Iron & 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). 

330Portland 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). 

331Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 

1981) was governed by the 1977 CAAA version of 

the definition of ‘‘standard of performance,’’ which 

revised the phrase ‘‘best system of emission 

reduction’’ to read, ‘‘best technological system of 

continuous emission reduction.’’ As noted above, 

the 1990 CAAA deleted ‘‘technological’’ and 

‘‘continuous’’ and thereby returned the phrase to 

how it read under the 1970 CAAA. The court’s 

interpretation of the 1977 CAAA phrase in Sierra 

Club v. Costle to require consideration of the 

amount of air emissions remains valid for the 1990 

CAAA phrase ‘‘best system of emission reduction.’’ 

332 79 FR 1430, 1465 (January 8, 2014) (citing 

Sierra Club v. Costle, 657 F.2d at 351). 

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

omitted) (citing legislative history). 

334Sierra Club v. Costle, 657 F.2d at 327–28 

(quoting 44 FR at 33583/3–33584/1). In the January 

2014 proposal, we explained that although the D.C. 

Circuit decided Sierra Club v. Costle before the 

Chevron case was decided in 1984, the D.C. 

Circuit’s decision could be justified under either 

Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 

2014). 

so that a control technology may be 

considered the ‘‘best system of emission 

reduction . . . adequately 

demonstrated’’ if its costs are 

reasonable, but cannot be considered 

the best system if its costs are 

unreasonable.325 326

The D.C. Circuit has repeatedly 

upheld the EPA’s consideration of cost 

in reviewing standards of performance. 

In several cases, the Court upheld 

standards that entailed significant costs, 

consistent with Congress’s view that 

‘‘the costs of applying best practicable 

control technology be considered by the 

owner of a large new source of pollution 

as a normal and proper expense of doing 

business.’’ 327 See Essex Chemical Corp. 

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

Cir. 1973); 328 Portland Cement 

Association v. Ruckelshaus, 486 F.2d 

375, 387–88 (D.C. Cir. 1973); Sierra Club 

v. Costle, 657 F.2d 298, 313 (D.C. Cir. 

1981) (upholding standard imposing 

controls on SO2 emissions from coalfired power plants when the ‘‘cost of the 

new controls . . . is substantial’’).329

As discussed below, the EPA may 

consider costs on both a source-specific 

basis and a sector-wide, regional, or 

nationwide basis. 

(b) Non-Air Health and Environmental 

Impacts 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘any 

nonair quality health and environmental 

impact’’ in determining the BSER. As 

the D.C. Circuit has explained, this 

requirement makes explicit that a 

system cannot be ‘‘best’’ if it does more 

harm than good due to cross-media 

environmental impacts.330

(c) Energy Considerations 

Under CAA section 111(a)(1), the EPA 

is required to take into account ‘‘energy 

requirements.’’ As discussed below, the 

EPA may consider energy requirements 

on both a source-specific basis and a 

sector-wide, region-wide, or nationwide 

basis. Considered on a source-specific 

basis, ‘‘energy requirements’’ entails, for 

example, the impact, if any, of the 

system of emission reduction on the 

source’s own energy needs. 

(d) Amount of Emissions Reductions 

In the proposed rulemakings for this 

rule and the associated section 111(b) 

rule, we noted that although the 

definition of ‘‘standard of performance’’ 

does not by its terms identify the 

amount of emissions from the category 

of sources or the amount of emission 

reductions achieved as factors the EPA 

must consider in determining the ‘‘best 

system of emission reduction,’’ the D.C. 

Circuit has stated that the EPA must do 

so. See Sierra Club v. Costle, 657 F.2d 

298, 326 (D.C. Cir. 1981) (‘‘we can think 

of no sensible interpretation of the 

statutory words ‘‘best . . . system’’ 

which would not incorporate the 

amount of air pollution as a relevant 

factor to be weighed when determining 

the optimal standard for controlling . . . 

emissions’’).331 The fact that the 

purpose of a ‘‘system of emission 

reduction’’ is to reduce emissions, and 

that the term itself explicitly 

incorporates the concept of reducing 

emissions, supports the Court’s view 

that in determining whether a ‘‘system 

of emission reduction’’ is the ‘‘best,’’ the 

EPA must consider the amount of 

emission reductions that the system 

would yield. Even if the EPA were not 

required to consider the amount of 

emission reductions, the EPA has the 

discretion to do so, on grounds that 

either the term ‘‘system of emission 

reduction’’ or the term ‘‘best’’ may 

reasonably be read to allow that 

discretion. 

(e) Sector- or Nationwide Component of 

Factors in Determining the BSER 

As discussed in the January 2014 

proposal for the section 111(b) 

rulemaking and the proposal for this 

rulemaking, another component of the 

D.C. Circuit’s interpretations of CAA 

section 111 is that the EPA may 

consider the various factors it is 

required to consider on a national or 

regional level and over time, and not 

only on a plant-specific level at the time 

of the rulemaking.332 The D.C. Circuit 

based this interpretation—which it 

made in the 1981 Sierra Club v. Costle 

case, which concerned the NSPS for 

new power plants—on a review of the 

legislative history, stating, 

[T]he Reports from both Houses on the 

Senate and House bills illustrate very clearly 

that Congress itself was using a long-term 

lens with a broad focus on future costs, 

environmental and energy effects of different 

technological systems when it discussed 

section 111.333

The Court has upheld EPA rules that the 

EPA ‘‘justified . . . in terms of the 

policies of the Act,’’ including balancing 

long-term national and regional impacts: 

The standard reflects a balance in 

environmental, economic, and energy 

consideration by being sufficiently stringent 

to bring about substantial reductions in SO2

emissions (3 million tons in 1995) yet does 

so at reasonable costs without significant 

energy penalties . . . . By achieving a 

balanced coal demand within the utility 

sector and by promoting the development of 

less expensive SO2 control technology, the 

final standard will expand environmentally 

acceptable energy supplies to existing power 

plants and industrial sources. 

By substantially reducing SO2 emissions, 

the standard will enhance the potential for 

long term economic growth at both the 

national and regional levels.334

In this rule, the EPA is considering 

costs and energy implications on the 


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335Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 

(D.C. Cir. 1981). 

336Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 

427, 433–34 (D.C. Cir. 1973), cert. denied, 416 U.S. 

969 (1974). 

337Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, 

n.46 (D.C. Cir. 1980). 

338Sierra 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). 

339 40 CFR 60.21(e). 

340Sierra 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.’’). 

341See S. Rep. No. 91–1196 at 16 (1970) 

(‘‘Standards of performance should provide an 

incentive for industries to work toward constant 

improvement in techniques for preventing and 

controlling emissions from stationary sources’’); S. 

Rep. No. 95–127 at 17 (1977) (cited in Sierra Club 

v. Costle, 657 F.2d at 346 n. 174) (‘‘The section 111 

Standards of Performance . . . sought to assure the 

use of available technology and to stimulate the 

development of new technology’’). 

342See 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’’). 

343See 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’’). 

344See Sierra Club v. Costle, 657 F.2d at 351 

(upholding a standard of performance designed to 

promote the use of an emerging technology). 

basis of (i) their source-specific impacts 

and (ii) a sector-wide, regional, or 

national basis, both separately and in 

combination with each other. 

(4) Achievability of the Emission 

Limitation in the Emission Guidelines 

Before discussing the requirement 

under section 111(d) that the emission 

limitation in the emission guidelines 

must be ‘‘achievable,’’ it is useful to 

discuss the comparable requirement 

under section 111(b) for new sources. 

For new sources, CAA section 

111(b)(1)(B) and (a)(1) provides that the 

EPA must establish ‘‘standards of 

performance,’’ which are standards for 

emissions that reflect the degree of 

emission limitation that is ‘‘achievable’’ 

through the application of the BSER. 

According to the D.C. Circuit, a standard 

of performance is ‘‘achievable’’ if a 

technology can reasonably be projected 

to be available to an individual source 

at the time it is constructed that will 

allow it to meet the standard.335

Moreover, according to the Court, ‘‘[a]n 

achievable standard is one which is 

within the realm of the adequately 

demonstrated system’s efficiency and 

which, while not at a level that is purely 

theoretical or experimental, need not 

necessarily be routinely achieved within 

the industry prior to its adoption.’’ 336

To be achievable, a standard ‘‘must be 

capable of being met under most 

adverse conditions which can 

reasonably be expected to recur and 

which are not or cannot be taken into 

account in determining the ‘costs’ of 

compliance.’’ 337 To show a standard is 

achievable, the EPA must ‘‘(1) identify 

variable conditions that might 

contribute to the amount of expected 

emissions, and (2) establish that the test 

data relied on by the agency are 

representative of potential industrywide performance, given the range of 

variables that affect the achievability of 

the standard.’’ 338

The D.C. Circuit established these 

standards for achievability in cases 

concerning CAA section 111(b) new 

source standards of performance. There 

is no case law under CAA section 

111(d). Assuming that those standards 

for achievability apply under section 

111(d), in this rulemaking, we are taking 

a similar approach for the emission 

limitation that the EPA identifies in the 

emission guidelines. For existing 

sources, section 111(d)(1) requires the 

EPA to establish requirements for state 

plans that, in turn, must include 

‘‘standards of performance.’’ Through 

long-standing regulations 339 and 

consistent practice, the EPA has 

interpreted this provision to require the 

EPA to promulgate emission guidelines 

that determine the BSER for a source 

category and that identify the amount of 

emission limitation achievable by 

application of the BSER. 

The EPA has promulgated these 

emission guidelines on the basis that the 

existing sources can achieve the 

limitation, even though the state retains 

discretion to apply standards of 

performance to individual sources that 

are more or less stringent. 

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 text.340 In 

addition, the Court’s interpretation finds 

firm support in the legislative 

history.341 The legislative history 

identifies three different ways that 

Congress designed CAA section 111 to 

authorize standards of performance that 

promote technological improvement: (i) 

The development of technology that 

may be treated as the ‘‘best system of 

emission reduction . . . adequately 

demonstrated;’’ under section 

111(a)(1); 342 (ii) the expanded use of the 

best demonstrated technology; 343 and 

(iii) the development of emerging 

technology.344 Even if the EPA were not 

required to consider technological 

innovation as part of its determination 

of the BSER, it would be reasonable for 

the EPA to consider it, either because 

technological innovation may be 

considered an element of the term 

‘‘best,’’ or because the term ‘‘best system 

of emission reduction’’ is ambiguous as 

to whether technological innovation 

may be considered, and it is reasonable 

for the EPA to interpret it to authorize 

consideration of technological 

innovation in light of Congress’s 

emphasis on technological innovation. 

In any event, as discussed below, the 

EPA may justify the control measures 

identified in this rule as the BSER even 

without considering the factor of 

incentivizing technological innovation 

or development. 

(6) EPA Discretion 

The D.C. Circuit has made clear that 

the EPA has broad discretion in 

determining the appropriate standard of 

performance under the definition in 

CAA section 111(a)(1), quoted above. 

Specifically, in Sierra Club v. Costle, 

657 F.2d 298 (D.C. Cir. 1981), the Court 

explained that ‘‘section 111(a) explicitly 

instructs the EPA to balance multiple 

concerns when promulgating a 


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

346Sierra 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). 

347 Lignite Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999) (paragraphing revised for 

convenience). See New York v. Reilly, 969 F.2d 

1147, 1150 (D.C. Cir. 1992) (‘‘Because Congress did 

not assign the specific weight the Administrator 

should accord each of these factors, the 

Administrator is free to exercise his discretion in 

this area.’’); see also NRDC v. EPA, 25 F.3d 1063, 

1071 (D.C. Cir. 1994) (EPA did not err in its final 

balancing because ‘‘neither RCRA nor EPA’s 

regulations purports to assign any particular weight 

to the factors listed in subsection (a)(3). That being 

the case, the Administrator was free to emphasize 

or deemphasize particular factors, constrained only 

by the requirements of reasoned agency 

decisionmaking.’’). 

348 40 CFR 60.22(b)(5). 

349 In this rulemaking, our determination that the 

costs are reasonable means that the costs meet the 

cost standard in the case law no matter how that 

standard is articulated, that is, whether the cost 

standard is articulated through the terms that the 

case law uses, e.g., ‘‘exorbitant,’’ ‘‘excessive,’’ etc., 

or through the term we use for convenience, 

‘‘reasonableness’’. 

350The approaches that states may take in their 

plans are discussed in section VIII. 

NSPS,’’ 345 and emphasized that ‘‘[t]he 

text gives the EPA broad discretion to 

weigh different factors in setting the 

standard.’’ 346 In Lignite Energy Council 

v. EPA, 198 F.3d 930 (D.C. Cir. 1999), 

the Court reiterated: 

Because section 111 does not set forth the 

weight that should be assigned to each of 

these factors, we have granted the agency a 

great degree of discretion in balancing 

them. . . . EPA’s choice [of the ‘best 

system’] will be sustained unless the 

environmental or economic costs of using the 

technology are exorbitant. . . . EPA [has] 

considerable discretion under section 111.347

d. Approach to the source category 

and subcategorizing. Section 111 

requires the EPA first to list source 

categories that may reasonably be 

expected to endanger public health or 

welfare and then to regulate new 

sources within each such source 

category. Section 111(b)(2) grants the 

EPA discretion whether to ‘‘distinguish 

among classes, types, and sizes within 

categories of new sources for the 

purpose of establishing [new source] 

standards,’’ which we refer to as 

‘‘subcategorizing.’’ Section 111(d)(1), in 

conjunction with section 111(a)(1), 

simply requires the EPA to determine 

the BSER, does not prescribe the 

method for doing so, and is silent as to 

whether the EPA may subcategorize. 

The EPA interprets this provision to 

authorize the EPA to exercise discretion 

as to whether and, if so, how to 

subcategorize. In addition, the 

regulations under CAA section 111(d) 

provide that the Administrator will 

specify different emission guidelines or 

compliance times or both ‘‘for different 

sizes, types, and classes of designated 

facilities when costs of the control, 

physical limitations, geographical 

location, or similar factors make 

subcategorization appropriate.’’ 348

As with any of its own regulations, 

the EPA has authority to interpret or 

revise these regulations. 

Of course, regardless of whether the 

EPA subcategorizes within a source 

category for purposes of determining the 

BSER and the emissions performance 

level for the emission guideline, as part 

of its CAA 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 order to establish the 

BSER we have considered the 

subcategory of the steam affected EGUs 

as a whole, and the subcategory of the 

combustion turbine affected EGUs as a 

whole, and have identified the BSER for 

each subcategory as the measures that 

the sources, viewed together and 

operating under the standards of 

performance established for them by the 

states, can implement to reduce their 

emissions to an appropriate amount, 

and that meet the other requirements for 

the BSER including, for example, cost 

reasonableness.349 After identifying the 

BSER in this manner, the EPA 

determines the performance levels—in 

this case, the CO2 emission performance 

rates—for the steam generators and for 

the combustion turbines. 

In establishing the BSER the EPA also 

considered the set of actions that an 

EGU, operating under a standard of 

performance established by its state, 

may take to achieve the applicable 

performance rate, if the state adopts that 

rate as the standard of performance and 

applies it to the EGUs in its jurisdiction, 

or to achieve the equivalent mass-based 

limit, and that meet the other 

requirements for the BSER. These 

actions implement the BSER and may 

therefore be understood as part of the 

BSER. 

An example illustrating the 

relationship between the measures 

determined to constitute the BSER for 

the source category and the actions that 

may be undertaken by individual 

sources that are therefore also part of the 

BSER is the substitution of zero-emitting 

generation for CO2-emitting generation. 

This measure involves two distinct 

actions: Increasing the amount of zeroemitting generation and reducing the 

amount of CO2-emitting generation. 

From the perspective of the source 

category, the two actions are halves of 

a single balanced endeavor, but from the 

perspective of any individual affected 

EGU, the two actions are separable, and 

a particular affected EGU may decide to 

implement either or both of the actions. 

Further, an individual source may 

choose to invest directly in actions at its 

own facility or an affiliated facility or to 

cross-invest in actions at other facilities 

on the interconnected electricity system. 

To reiterate the overall context for the 

BSER: In this rule, the EPA determined 

the BSER, and applied it to the category 

of affected EGUs to determine the 

performance levels—that is, the CO2

emission performance rates—for steam 

generators and for combustion turbines. 

States must impose standards of 

performance on their sources that 

implement the CO2 emission 

performance rates, or, as an alternative 

method of compliance, in total, achieve 

the equivalent emissions performance 

level that the CO2 emission performance 

rates would achieve if applied directly 

to each source as the standard or 

emissions limitation it must meet.350

Each state has flexibility in how it 

assigns the emission limitations to its 

affected EGUs—and in fact, the state can 

be more stringent than the guidelines 

require—but one of the state’s choices is 

to convert the CO2 emission 

performance rates into standards of 

performance—which may incorporate 

emissions trading—for each of its 

affected EGUs. If a state does so, then 

the affected EGUs may achieve their 

emission limits by taking the actions 

that qualify as the BSER. Since the 

BSER and, in this case its constituent 

elements, reflect the criteria of 

reasonable cost and other BSER criteria, 

the BSER assures that there is at least 

one pathway—the CO2 emission 

performance rates—for the state and its 

affected EGUs to take that achieves the 

requisite level of emission reductions, 

while, again, assuring that the affected 

EGUs can achieve those emission limits 


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351Other sections in this preamble describe how 

EPA calculated the CO2 emission performance rates 

based on the BSER. 

352The building block measures are not designed 

to reduce electricity generation overall; they are 

focused on maintaining the same level of electricity 

generation, but through less polluting processes. 

353Conditions for the use of these mechanisms 

under various state plans are discussed in section 

VIII. 

354Again, conditions for the use of these 

mechanisms under various state plans are discussed 

in section VIII. 

355The 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. 

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

357 44 FR 33580, 33593. The EPA considered an 

investigation by the U.S. Department of the Interior 

regarding the amount of sulfur that could be 

removed from various coals by physical coal 

cleaning. Id. at 33593. 

358See 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’’). 

359 61 FR 9905, 9905 (March 12, 1996). In the 

rule, the EPA referred to the BSER for both new and 

existing MSW landfills as ‘‘the best demonstrated 

system of continuous emission reduction,’’ as well 

as the ‘‘BDT’’—short for ‘‘best demonstrated 

technology.’’ See, e.g., id. at 9905–07, 9913–14. 

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.351 The 

EPA is identifying the BSER as a wellestablished set of measures that have 

been used by EGUs for many years to 

achieve various business and policy 

purposes, and have been used in recent 

years for the specific purpose of 

reducing EGUs’ CO2 emissions, and that 

are appropriate for carbon pollution 

(given its global nature and large 

quantities, and the limited means to 

control it) and afforded by the highly 

integrated nature of the utility power 

sector. We evaluated these measures 

with a view to the states’ obligation to 

establish standards of performance and 

included in our BSER determination 

consideration of the range of options 

available for states to employ in 

establishing those standards of 

performance. These measures include: 

(i) Improving heat rate at existing coalfired steam EGUs on average by a 

specified percentage (building block 1); 

(ii) substituting increased generation 

from existing NGCC units for reduced 

generation at existing steam EGUs in 

specified amounts (building block 2); 

and (iii) substituting increased 

generation from new zero-emitting RE 

generating capacity for reduced 

generation at existing fossil fuel-fired 

EGUs in specified amounts (building 

block 3). It should be noted that 

building block 2 incorporates reduced 

generation from steam EGUs and 

building block 3 incorporates reduced 

generation from all fossil fuel-fired 

EGUs.352 Further, as discussed below, 

given the global nature of carbon 

pollution and the highly integrated 

utility power sector, each of the 

building blocks incorporates various 

mechanisms for facilitating 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 acquisition of ERCs 

representing the emissions-reducing 

effects of specific activities, where 

available under state plans; and more 

general emissions trading using ratebased credits or mass-based allowances 

(as discussed in section V.A.2.f. below), 

where the affected EGUs are operating 

under standards of performance that 

incorporate emissions trading.353

The set of measures identified as the 

BSER for the source category 

encompasses a menu of actions that are 

part of the BSER and that individual 

affected EGUs may implement in 

different amounts and combinations in 

order to achieve their emission limits at 

reasonable cost. This menu includes 

actions that: (i) Affected steam EGUs 

can implement to improve their heat 

rates; (ii) affected steam EGUs can 

implement to increase generation from 

lower-emitting existing NGCC units in 

specified amounts; (iii) all affected 

EGUs can implement to increase 

generation from new low- or 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.354

Importantly, affected EGUs also have 

available numerous other measures that 

are not included in the BSER but that 

could materially help the EGUs achieve 

their emission limits and thereby 

provide compliance flexibility. 

Examples include, among numerous 

other approaches, investment in 

demand-side EE, 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 discussed 

by commenters and our further 

evaluation. What follows is the EPA’s 

final determination. 

As described in the proposal, to 

determine the BSER, the EPA began by 

considering the characteristics of CO2

pollution and the utility power sector. 

Not surprisingly, whenever the EPA 

begins the regulatory process under 

section 111, it initially undertakes these 

same inquiries and then proceeds to 

fashion the rule to fit the industry. For 

example, in 1979, the EPA finalized 

new standards of performance to limit 

emissions of SO2 from new, modified, 

and reconstructed EGUs.355 In assessing 

the final SO2 standard, the EPA carried 

out extensive analyses of a range of 

alternative SO2 standards ‘‘to identify 

environmental, economic, and energy 

impacts associated with each of the 

alternatives considered at the national 

and regional levels.’’ 356 In identifying 

the best system underlying the final 

standard, the EPA evaluated ‘‘coal 

cleaning and the relative economics of 

FGD [flue gas desulfurization] and coal 

cleaning’’ together as the ‘‘best 

demonstrated system for SO2 emission 

reduction.’’ 357 The EPA also took into 

account the unique features of power 

transmission along the interconnected 

grid and the unique commercial 

relationships that rely on those 

features.358

Similarly, in 1996, the EPA finalized 

section 111(b) standards and 111(d) 

emission guidelines to ensure that 

certain municipal solid waste (MSW) 

landfills controlled landfill gases to the 

level achievable through application of 

the BSER.359 EPA’s identification of this 

BSER was critically influenced by the 

‘‘unique emission pattern of 


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360 61 FR 9905, 9908; see 56 FR 24468, 24478 

(May 30, 1991) (explaining at proposal that because 

landfill-gas emission rates ‘‘gradually increase’’ 

from zero after the landfill opens, and ‘‘gradually 

decrease’’ from peak emissions after closure, the 

EPA’s identification of the BSER for landfills 

inherently requires a determination of ‘‘when 

controls systems must be installed and when they 

may be removed’’). 

361See U.S. EPA, Municipal Solid Waste 

Landfills, Volume 1: Summary of the Requirements 

for the New Source Performance Standards and 

Emission Guidelines for Municipal Solid Waste 

Landfills, Docket No. EPA–453R/96–004 at 1–3 

(February 1999). 

362 61 FR 9905, 9907–08. 

363 61 FR 9905, 9908. 

364S. 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). 

365These trends are discussed in more detail in 

sections V.D. and V.E. below. 

366 Demand-side energy efficiency measures have 

also increased, and the projected future trends are 

for continued increase. 

367See memorandum entitled ‘‘Review of Electric 

Utility Integrated Resource Plans’’ (May 7, 2015) 

available in the docket. 

368See 79 FR 34848–34850. 

369Many of these programs are discussed in 

section II. 

landfills.’’ 360 Unlike ‘‘typical stationary 

source[s],’’ which only generate 

emissions while in operation, MSW 

landfills can ‘‘continue to generate and 

emit a significant quantity of emissions’’ 

long after the facility has closed or 

otherwise stopped accepting waste.361

In recognition of this salient and unique 

characteristic of landfills, the EPA set 

the BSER based on an emissionreducing system of gas collection and 

control that remained in place as long 

as emissions remained above a certain 

threshold—even after the regulated 

landfill had permanently closed.362 The 

EPA acknowledged that for some 

landfills, it could take 50 to 100 years 

for emissions to drop below the 

cutoff.363

For this rule, we discuss at length in 

the proposed rule and in section II 

above the unique characteristics of CO2

pollution. The salient facts include the 

global nature of CO2, which makes the 

specific location of emission reductions 

unimportant; the enormous quantities of 

CO2 emitted by the utility power sector, 

coupled with the fact that CO2 is 

relatively unreactive, which make CO2

much more difficult to mitigate by 

measures or technologies that are 

typically utilized within an existing 

power plant; the need to make large 

reductions of CO2 in order to protect 

human health and the environment; and 

the fact that the utility power sector is 

the single largest source category by a 

considerable margin. 

We also discuss at length in the 

proposal and in section II above the 

unique characteristics of the utility 

power sector. Topics of that discussion 

include the physical properties of 

electricity and the integrated nature of 

the electricity system. Here, we reiterate 

and emphasize that the utility power 

sector is unique in the extent to which 

it must balance supply and demand on 

a real-time basis, with limited electricity 

storage capacity to act as a buffer. In 

turn, the need for real-time 

synchronization across each 

interconnection has led to a uniquely 

high degree of coordination and 

interdependence in both planning and 

real-time system operation among the 

owners and operators of the facilities 

comprised within each of the three large 

electrical interconnections covering the 

contiguous 48 states. Given these 

unique characteristics, it is not 

surprising that the North American 

power system has been characterized as 

a ‘‘complex machine.’’ 364 The core 

function of providing reliable electricity 

service is carried out not by individual 

electricity generating units but by the 

complex machine as a whole. Important 

subsidiary functions such as 

management of costs and management 

of environmental impacts are also 

carried out to a great extent on a multiunit basis rather than an individual-unit 

basis. Generation from one generating 

unit can be and routinely is substituted 

for generation from another generating 

unit in order to keep the complex 

machine operating while observing the 

machine’s technical, environmental, 

and other constraints and managing its 

costs. 

The EPA also reviewed broad trends 

within the utility power sector.365 It is 

evident that, in the recent past, coalfired electricity generation has been 

reduced, and projected future trends are 

for continued reduction. By the same 

token, lower-emitting NGCC generation 

and renewable generation have 

increased, and projected future trends 

are for continued increases.366 A survey 

of integrated resource plans (IRPs), 

included in the docket, shows that fossil 

fuel-fired EGUs are taking actions to 

reduce emissions of both non-GHG air 

pollutants and GHGs.367 Some fossil 

fuel-fired EGUs are investing in loweror zero-emitting generation. In fact, our 

review indicates that the great majority 

of fossil fuel-fired generators surveyed 

are including new RE resources in their 

planning. In addition, some fossil fuelfired EGUs are using those measures to 

replace their higher-emitting generation. 

Some fossil fuel-fired generators appear 

to be reducing their higher-emitting 

generation without fully replacing it 

themselves. These measures in aggregate 

result in the replacement of higheremitting 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.368

They also include market-based 

initiatives, such as RGGI and the GHG 

emissions trading program established 

by the California Global Warming 

Solutions Act, and conservation and 

demand reduction programs. 

We also examined federal legislative 

and regulatory programs, as well as state 

programs currently in operation, that 

address pollutants other than CO2

emitted by the power sector. These 

programs include, among others, the 

CAA Title IV program to reduce SO2

and NOX, the MATS program to reduce 

mercury and air toxic emissions, and 

the CSAPR program to reduce SO2 and 

NOX.369 This analysis demonstrated 

that, among other measures, the 

application of control technology, fuelswitching, and improvements in the 

operational efficiency of EGUs all 

resulted in reductions in a range of 

pollutants. These programs also 

demonstrate that replacement of higheremitting generation with lower-emitting 

generation—including generation shifts 

between coal-fired EGUs and natural 

gas-fired EGUs and generation shifts 

between fossil fuel-fired EGUs and RE 

generation—also reduces emissions. 

Some of these programs also include 

emissions trading among the power 

plants. 

In this rule, when evaluating the types 

and amounts of measures that the 

source category can take to reduce CO2

emissions, we have appropriately taken 

into account the global nature of the 

pollutant and the high degree to which 

each individual affected EGU is 

integrated into a ‘‘complex machine’’ 

that makes it possible for generation 

from one generating unit to be replaced 

with generation from another generating 

unit for the purpose of reducing 

generation from CO2-emitting generating 

units. We have also taken into account 

the trends away from higher-carbon 

generation toward lower- and zerocarbon generation. These factors 

strongly support consideration of 

emission reduction approaches that 


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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 sourcecategory level likewise strongly support 

consideration of mechanisms such as 

emissions trading approaches, 

especially since, as discussed in section 

VIII, the states will have every 

opportunity to design their section 

111(d) plans to allow the affected EGUs 

in their respective jurisdictions to 

employ emissions trading approaches to 

achieve the standards of performance 

established in those plans. In short, as 

discussed in more detail in section 

V.A.2.f. below, it is entirely feasible for 

states to establish standards of 

performance that incorporate emissions 

trading, and it is reasonable to expect 

that states will do so. These approaches 

lower overall costs, add flexibility, and 

make it easier for individual sources to 

address pollution control objectives. To 

the extent that the purchase of an 

emissions credit or allowance represents 

the purchase of surplus emission 

reductions by an emitting source, 

emissions trading represents, in effect, 

the investment in pollution control by 

the purchasing source, notwithstanding 

that the control activity may be 

occurring at another source. As noted 

above, the utility power sector has a 

long history of using the ‘‘complex 

machine’’ to address objectives and 

constraints of various kinds. When 

afforded the opportunity to address 

environmental objectives on a multiunit 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 

outreach process. The role of emissions 

trading is discussed further in section 

V.A.2.f. below. 

This entire review has made clear that 

there are numerous measures that, alone 

or in various combinations, merit 

analysis for inclusion in the BSER. The 

review has also made clear that the 

unique characteristics of CO2 pollution 

and the unique, interconnected and 

interdependent manner in which 

affected EGUs and other generating 

sources operate within the electricity 

sector make certain types of measures 

and mechanisms available and 

appropriate for consideration as the 

BSER for this rule that would not be 

appropriate for other pollutants and 

other industrial sectors. For purposes of 

this discussion, the measures can be 

categorized in terms of the essential 

characteristics of the four building 

blocks described in the proposal: 

measures that (i) reduce the CO2

emission rate at the unit; (ii) substitute 

generation from existing lower-emitting 

fossil fuel-fired units for generation 

from higher-emitting fossil fuel-fired 

units; (iii) substitute generation from 

new low- or zero-emitting generating 

capacity, especially RE, for generation 

from fossil fuel-fired units; and (iv) 

increase demand-side EE to avoid 

generation from fossil fuel-fired units. In 

the proposal, we described our 

evaluations of various measures in each 

of these categories. In this rule, with the 

benefit of comments, we have refined 

our evaluation of which specific 

measures should comprise the first three 

building blocks, and, for reasons 

discussed below, we have determined 

that the fourth building block, demandside EE, should not be included in the 

BSER in these guidelines. 

The measures are discussed more 

fully below, but it should be noted here 

that because of the integrated nature of 

the utility power sector—in which 

individual EGUs’ operations 

intrinsically depend on the operations 

of other generators—coupled with the 

sector’s high degree of planning and 

reliability safeguards, the measures in 

the second and third categories (which 

involve generation shifts to lower- and 

zero-emitting sources) may occur 

through several different actions from 

the perspective of an individual source, 

all of which are equivalent from the 

perspective of the source category as a 

whole. First, a higher-emitting fossil 

unit may invest in cleaner generation 

without reducing its own generation, 

which, in the presence of requirements 

for the source category as a whole to 

reduce CO2 emissions, would result in 

less demand for, and therefore 

reductions in generation by, other 

higher-emitting units. Second, a higheremitting fossil unit may reduce its 

generation, which, in the presence of 

requirements for the source category as 

a whole to reduce CO2 emissions, would 

result in increased demand for, and 

therefore increased amounts of, cleaner 

generation. Third, a higher-emitting 

fossil unit may do both of these things, 

directly replacing part of its generation 

with investments in lower- or zeroemitting generation. In addition, for 

measures in all of the categories, 

multiple mechanisms exist by which an 

individual affected EGU may make 

these investments, ranging from 

bilateral investments, to purchase of 

credits representing the emissionsreducing benefits of specific activities, 

to purchase of general rate-based 

emissions credits or mass-based 

emission allowances. As discussed 

below, mechanisms involving tradable 

credits or allowances are well within 

the realm of consideration for the 

standards of performance states can 

choose to apply to their EGUs and 

hence, are entirely appropriate for EPA 

to consider in evaluating these measures 

in the course of making its BSER 

determination. 

c. State establishment of standards of 

performance and source compliance. 

Before identifying in detail the measures 

that the BSER comprises, it is useful to 

describe the process by which the states 

establish the standards of performance 

with which the affected EGUs must 

comply, and the implications for the 

sources that will be operating subject to 

those standards of performance. As part 

of the EPA’s emission guidelines in this 

rule, and based on the BSER, the EPA 

is identifying CO2 emission performance 

rates that reflect the BSER and, pursuant 

to subsection 111(d)(1), requiring states 

to establish standards of performance 

for affected EGUs in order to implement 

those rates. States, of course, could 

simply impose those rates on each 

affected EGU in their respective 

jurisdictions, but we are also offering 

states alternative approaches to carrying 

out their obligations. For purposes of 

defining these alternatives and 

facilitating states’ efforts to formulate 

compliance plans encompassing 

maximum flexibilities, we are 

aggregating the performance rates into 

goals for each state. The state, in turn, 

has the option of setting specific 

standards of performance for its EGUs 

such that the emission limitations from 

the EGUs operating under those 

standards of performance together meet 

the performance rates or the state goal. 

To do this, the state must adopt a plan 

that establishes the EGUs’ standards of 


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370As further discussed below, if heat rate 

improvements at coal-fired steam EGUs were 

implemented in isolation, without other measures 

to reduce CO2 emissions, the heat rate 

improvements could lead to increases in 

competitiveness and utilization of the coal-fired 

EGUs—a so-called ‘‘rebound effect’’—causing 

increases in CO2 emissions that could partially or 

even entirely offset the CO2 emission reductions 

achieved through the reductions in the amount of 

CO2 emissions per MWh of generation. 

371The EPA further addressed co-firing in the 

October 30, 2014 NODA. 79 FR 64549–51. 

372CCS is also sometimes referred to as carbon 

capture and sequestration. 

performance and that implements and 

enforces those standards. 

Each state has significant flexibility in 

several respects. For example, as 

mentioned, a state may impose 

standards of performance on its steam 

EGU sources and on its combustion 

turbine sources that simply reflect the 

respective CO2 emission performance 

rates for those subcategories set in the 

emission guidelines. Alternatively, a 

state may impose standards with 

differing degrees of stringency on 

various sources, and, in fact, may be 

more stringent overall than its state goal 

requires. In addition—and most 

importantly for purposes of describing 

the BSER—a state may set standards of 

performance as mass limits (e.g., tons of 

CO2 per year) rather than as emission 

rates (e.g., lbs of CO2 per MWh). 

Moreover, a state may make the limits 

tradable (subject to conditions described 

in section VIII below), whether the 

limits are rate-based or mass-based. The 

form of the emission limits, whether 

emission rate limits or mass limits, has 

implications for what specific actions 

that are part of the BSER the individual 

affected EGUs may take to achieve those 

limits as well as what specific nonBSER measures are available to the 

individual affected EGUs for 

compliance flexibility. For example, if 

an individual source chooses to adopt 

building block 3 by both investing in 

lower- or zero-emitting generation and 

reducing its own generation, both those 

actions will be accounted for in its 

emission rate and both will therefore 

help the source meet its rate-based limit. 

If the same individual source takes the 

same actions but is subject to a massbased limit, the action of reducing its 

generation will directly count in helping 

the source meet its own mass-based 

limit but the action of investing in 

cleaner generation will not. However, 

the investment in lower-or zero-emitting 

generation by that source and other 

sources collectively will help the overall 

source category achieve the emission 

limits consistent with the BSER and in 

doing so will make it easier for that 

source and other sources collectively to 

meet their mass-based limits. 

In instances where a state establishes 

standards of performance that 

incorporate emissions trading, the 

tradable credits or allowances can serve 

as a medium through which affected 

EGUs can invest in any emission 

reduction measure. 

d. Identification of the BSER 

measures. We now discuss the 

evaluation of potential measures for 

inclusion in the BSER for the source 

category as a whole. 

(1) Measures that reduce individual 

affected EGUs’ CO2 emission rates. 

As described in the proposal, the 

measures that the affected EGUs could 

implement to improve their CO2

emission rates include a set of measures 

that the EPA determined would result in 

improvements in heat rate at coal-fired 

steam EGUs in the amount of 6 percent 

on average, and the EPA proposed that 

this set of measures qualifies as a 

component of the BSER. In this final 

rule, the EPA concludes that those 

measures do qualify as a component of 

the BSER. However, as described in 

section V.C. below, based on responsive 

comments and further evaluation, the 

EPA has refined its approach to 

quantifying the emission reductions 

achievable through heat rate 

improvements and no longer includes a 

separate increment of emission 

reductions attributable to equipment 

upgrades. Also, rather than evaluating 

the emission reductions available from 

these measures on a nationwide basis as 

in the proposal, the EPA has quantified 

the emission reductions achievable 

through building block 1 on a regional 

basis, consistent with the EPA’s 

proposals to better reflect the regional 

nature of the interconnected electrical 

system and the treatment of the other 

building blocks in this final rule. As a 

result of these refinements, the EPA is 

identifying the heat rate improvements 

achievable by coal-fired steam EGUs as 

4.3 percent for the Eastern 

Interconnection, 2.1 percent for the 

Western Interconnection, and 2.3 

percent for the Texas Interconnection. 

The refinements are based, in significant 

part, on the numerous comments we 

received on our proposed approaches, 

especially those from states and 

utilities. 

These heat rate improvement 

measures include best practices such as 

improved staff training, boiler chemical 

cleaning, cleaning air preheater coils, 

and use of various kinds of software, as 

well as equipment upgrades such as 

turbine overhauls. These are measures 

that the owner/operator of an affected 

coal-fired steam EGU may take that 

would have the effect of reducing the 

amount of CO2 the source emits per 

MWh. As a result, these measures 

would help the source achieve an 

emission limit expressed as either an 

emission rate limit or as a mass limit. 

We note again that in the context both 

of the integrated electricity system and 

of available and anticipated state 

approaches to setting standards of 

performance, emissions trading 

approaches could be used as 

mechanisms through which one affected 

EGU could invest in heat rate 

improvements at another EGU. We note 

this aspect below in describing the 

actions an individual affected EGU can 

take to implement the BSER and discuss 

it in more detail in section V.A.2.f. 

These heat rate improvements are a 

low-cost option that fit the criteria for 

the BSER, except that they lead to only 

small emission reductions for the source 

category.370 Given the magnitude of the 

environmental problem and projections 

by climate scientists that much larger 

emission reductions are needed from 

fossil fuel-fired EGUs to address climate 

change, the EPA looked at additional 

measures to reduce emission rates. This 

reflects our conclusion that, given the 

availability of other measures capable of 

much greater emission reductions, the 

emission reductions limited to this set 

of heat rate improvement measures 

would not meet one of the 

considerations critical to the BSER 

determination—the quantity of 

emissions reductions 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 cofiring (including 100 percent 

conversion) with natural gas, a measure 

that presented itself in part because of 

the recent increase in availability and 

reduction in price of natural gas, and 

the industry’s consequent increase in 

reliance on natural gas.371 The EPA also 

considered implementation of carbon 

capture and storage (CCS).372 The EPA 

found that some of these co-firing and 

CCS measures are technically feasible 

and within price ranges that the EPA 

has found to be cost effective in the 

context of other GHG rules, that a 

segment of the source category may 

implement these measures, and that the 

resulting emission reductions could be 

potentially significant. 

However, these co-firing and CCS 

measures are more expensive than other 

available measures for existing sources. 

This is because the integrated nature of 

the electricity system affords 

significantly lower cost options, ones 

that fossil fuel-fired power plants 


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373Many EGUs would also rely on demand-side 

energy efficiency measures. 

throughout the U.S. and in foreign 

nations are already using to reduce their 

CO2 emissions. 

The less expensive options include 

shifting generation to existing NGCC 

units—an option that has become 

particularly attractive in light of the 

increased availability and lower prices 

of natural gas—as well as shifting 

generation to new RE generating units. 

A comparison of the costs of converting 

an existing coal-fired boiler to burn 100 

percent natural gas compared to the cost 

of shifting generation to an existing 

NGCC unit illustrates this point. 

Because an NGCC unit burns natural gas 

significantly more efficiently than an 

affected steam EGU does, the cost of 

shifting generation from the steam EGU 

to an existing NGCC unit is significantly 

cheaper in most cases than more 

aggressive emission rate reduction 

measures at the steam EGU. As a result, 

as a practical matter, were the EPA to 

include co-firing and CCS in the BSER 

and promulgate performance standards 

accordingly, few EGUs would likely 

comply with their emission standards 

through co-firing and CCS; rather, the 

EGUs would rely on the lower cost 

options of substituting lower- or zeroemitting generation or, as a related 

matter, reducing generation.373

The EPA also considered heat rate 

improvement opportunities at oil- and 

gas-fired steam EGUs and NGCC units 

and found that the available emission 

reductions would likely be more 

expensive or too small to merit 

consideration as a material component 

of the BSER. 

Thus, in reviewing the entire range of 

control options, it became clear that 

controlling CO2 from affected EGUs at 

levels that are commensurate with the 

sector’s contribution to GHG emissions 

and thus necessary to mitigate the 

dangers presented by climate change, 

could depend in part, but not primarily, 

on measures that improve efficiency at 

the power plants. Rather, most of the 

CO2 controls need to come in the form 

of those other measures that are 

available to the utility power sector 

thanks specifically to the integrated 

nature of the electricity system, and that 

involve, in one form or another, 

replacement of higher emitting 

generation with lower- or zero-emitting 

generation. 

Although the presence of lower-cost 

options that achieve the emission 

reduction goals means that the EPA is 

not identifying either natural gas cofiring 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 

preamble and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. 

(2) Measures available because of the 

integrated electricity system. 

To determine the BSER that meets the 

expectations and requirements of the 

CAA, including the achievement of 

meaningful reductions of CO2, the EPA 

turned next to the set of measures that 

presented themselves as a result of the 

fact that the operations of individual 

affected EGUs are interdependent on 

and integrated with one another and 

with the overall electricity system. 

Those are the measures in the categories 

represented in the proposal by building 

blocks 2, 3, and 4. This section 

discusses the components of the BSER 

that relate to building blocks 2 and 3, 

which the EPA is finalizing as 

components of the BSER. This section 

also discusses the measures comprising 

the proposed building block 4, which 

the EPA is not including in the BSER in 

this final rule. 

It bears reiterating that the extent to 

which the operations of individual 

affected EGUs are integrated with one 

another and with the overall electricity 

system is a highly salient and unique 

attribute of this source category. 

Because of this integration, the 

individual sources in the source 

category operate through a network that 

physically connects them to each other 

and to their customers, an 

interconnectedness that is essential to 

their operation under the status quo and 

by all indications is projected to be 

augmented further on a continual basis 

in the future to address fundamental 

objectives of reliability assurance and 

cost reduction. This physical 

interconnectedness exists to serve a set 

of interlocking regimes that, to a 

substantial extent, determine, if not 

dictate, any given EGU’s operations on 

a nearly moment-to-moment basis. In 

analyzing BSER from the perspective of 

the overall source category, because the 

affected EGUs are connected to each 

other operationally, a combination of 

dispatching and investment in lowerand zero-emitting generation allows the 

replacement of higher-emitting 

generation with lower-emitting and 

zero-emitting generation (measures in 

building blocks 2 and 3), and thereby 

reduces emissions while continuing to 

serve load. 

As noted above, substitution of 

higher-emitting generation for lower- or 

zero-emitting generation may include 

reduced generation, depending on the 

specific action taken by the individual 

EGU. Likewise, when incorporated into 

standards of performance, emissions 

trading mechanisms may be readily 

used for implementing these building 

blocks. We discuss these aspects below 

in describing the actions that individual 

sources may take to implement the 

building blocks. 

(a) Substituting generation from 

lower-emitting affected EGUs for 

generation from higher-emitting affected 

EGUs. 

In the proposal, the EPA observed that 

substantial CO2 emission reductions 

could be achieved at reasonable cost by 

increasing generation from existing 

NGCC units and commensurately 

reducing generation from steam EGUs. 

Because NGCC units produce much less 

CO2 per MWh of generation than steam 

EGUs—typically less than half as much 

CO2 as coal-fired steam EGUs, which 

account for most generation from steam 

EGUs—this generation shift reduces CO2

emissions. We also noted that because 

NGCC units can generate as much as 46 

percent more electricity from a given 

quantity of natural gas than a steam unit 

can, generation shifting from coal-fired 

steam EGUs to existing NGCC units is a 

more cost-effective strategy for reducing 

CO2 emissions from the source category 

than converting coal-fired steam EGUs 

to combust natural gas or co-firing coal 

and natural gas in steam EGUs. We 

proposed to find that shifting generation 

consistent with a 70 percent target 

utilization rate (based on nameplate 

capacity) for NGCC units was feasible 

and should be a component of the 

BSER. 

As described in section V.D. below, 

analysis reflecting consideration of the 

many comments we received on the 

EPA’s proposal with respect to this 

issue supports the inclusion of 

generation shifting from higher-emitting 

to lower-emitting EGUs as a component 

of the BSER. Shifting of generation 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64729 

among EGUs is an everyday occurrence 

within the integrated operations of the 

utility power sector that is used to 

ensure that electricity is provided to 

meet customer demands in the most 

economic manner consistent with 

system constraints. Generation shifting 

to lower-emitting units has been 

recognized as an approach for reducing 

emissions in other EPA rules such as 

CSAPR. 

The EPA’s analysis continues to show 

that the magnitude of emission 

reductions included in the proposed 

rule from generation shifting is 

achievable. In response to our request 

for comment on the proposed target 

utilization rates, some commenters 

stated that summer capacity ratings are 

a more appropriate basis upon which to 

compute a target utilization than 

nameplate capacity ratings used at 

proposal. We agree, and accordingly, 

using the same data on historical 

generation as at proposal, we have 

reanalyzed feasible NGCC utilization 

levels expressed in terms of summer 

capacity ratings and have found that a 

75 target utilization rate based on 

summer capacity ratings is feasible. 

The EPA is finalizing a determination 

that generation shift from higheremitting affected EGUs to loweremitting 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 generation from affected 

EGUs. 

Reducing generation from fossil fuelfired EGUs and replacing it with 

generation from lower- or zero-emitting 

EGUs is another method for reducing 

CO2 emissions from the utility power 

sector. In the proposal, the EPA 

identified RE generating capacity and 

nuclear generating capacity as potential 

sources of lower- or zero-CO2 generation 

that could replace higher-CO2

generation from affected EGUs. 

(i) Increased generation from new RE 

generating capacity. 

The EPA’s survey of trends and 

actions already being taken in the utility 

power sector indicated that RE 

generating capacity and generation have 

grown rapidly in recent years, in part 

because of the environmental benefits of 

shifting away from fossil fuel-fired 

generation and in part because of 

improved economics of RE generation 

relative to fossil fuel-fired generation. It 

is clear that increasing the amount of 

new RE generating capacity and 

allowing the increased RE generation to 

replace generation from fossil fuel-fired 

EGUs can reduce CO2 emissions from 

the affected source category. 

Accordingly, we proposed to include 

replacement of defined quantities of 

fossil generation by RE generation in the 

BSER. 

The EPA is finalizing the 

determination that substitution of RE 

generation from new RE generating 

capacity is a component of the BSER 

but, with the benefit of comments 

responding to the EPA’s proposals on 

regionalization and techno-economic 

analytic approaches, the EPA has 

adjusted the approach for determining 

the quantities of RE generation. As part 

of the adjustment in approach, we have 

also refocused the quantification solely 

on generation from new RE generating 

capacity rather than total (new and 

existing) RE generating capacity as in 

the proposal. Our quantification of the 

RE generation component of the BSER is 

discussed in section V.E. of the 

preamble and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. 

(ii) Increased and preserved 

generation from nuclear generating 

capacity. 

In the June 2014 proposal, the EPA 

also identified the replacement of 

generation from fossil fuel-fired EGUs 

with generation from nuclear units as a 

potential approach for reducing CO2

emissions from the affected source 

category. We proposed to include two 

elements of nuclear generation in the 

BSER: An element representing 

projected generation from nuclear units 

under construction; and an element 

representing preserved generation from 

existing nuclear generating capacity at 

risk of retirement, and we took comment 

on all aspects of these proposals. 

Like generation from new RE 

generating capacity, generation from 

new nuclear generating capacity can 

clearly replace fossil fuel-fired 

generation and thereby reduce CO2

emissions. However, there are also 

important differences between these 

types of low- or zero-CO2 generation. 

Investments in new nuclear capacity are 

very large capital-intensive investments 

that require substantial lead times. By 

comparison, investments in new RE 

generating capacity are individually 

smaller and require shorter lead times. 

Also, important recent trends evidenced 

in RE development, such as rapidly 

growing investment and rapidly 

decreasing costs, are not as clearly 

evidenced in nuclear generation. We 

view these factors as distinguishing the 

under-construction nuclear units from 

RE generating capacity, indicating that 

the new nuclear capacity is likely of 

higher cost and therefore less 

appropriate for inclusion in the BSER. 

Accordingly, as described in section 

V.A.3., the EPA is not finalizing 

increased generation from underconstruction nuclear capacity as a 

component of the BSER. 

The EPA is likewise not finalizing the 

proposal to include a component 

representing preserved existing nuclear 

generation in the BSER. On further 

consideration, we believe it is 

inappropriate to base the BSER on 

elements that will not reduce CO2

emissions from affected EGUs below 

current levels. Existing nuclear 

generation helps make existing CO2

emissions lower than they would 

otherwise be, but will not further lower 

CO2 emissions below current levels. 

Accordingly, as described in section 

V.A.3., the EPA is not finalizing 

preservation of generation from existing 

nuclear capacity as a component of the 

BSER. 

(iii) Generation from new NGCC units. 

New NGCC units—that is, units that 

had not commenced construction as of 

January 8, 2014, the date of publication 

of the proposed CO2 standards of 

performance for new EGUs under 

section 111(b)—are not subject to the 

standards of performance that will be 

established for existing sources under 

section 111(d) plans based on the BSER 

determined in this final rule. In the June 

2014 proposed emission guidelines for 

existing EGUs, the EPA solicited 

comment on whether to include this 

measure in the BSER. Commenters 

raised numerous concerns, and after 

consideration of the comments, we are 

not including replacement of generation 

from affected EGUs through the 

construction of new NGCC capacity in 

the BSER. In this section, we discuss the 

reasons for our approach. 

The EPA did not include reduced 

generation from affected EGUs achieved 

through construction and operation of 

new NGCC capacity in the proposed 

BSER because we expected that the CO2

emission reductions achieved through 

such actions would, on average, be more 

costly than CO2 emission reductions 

achieved through the proposed BSER 

measures. However, our determination 

not to include new construction and 

operation of new NGCC capacity in the 

BSER in this final rule rests primarily 

on the achievable magnitude of 

emission reductions rather than costs. 

Unlike emission reductions achieved 

through the use of any of the building 

blocks, emission reductions achieved 

through the use of new NGCC capacity 

require the construction of additional 

CO2-emitting generating capacity, a 

consequence that is inconsistent with 


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64730 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

374Specifically, the annual CO2 emission 

performance rates applicable to steam EGUs in all 

three interconnections are the annual emission rates 

achievable by that subcategory in the Eastern 

Interconnection through application of the building 

blocks. Similarly, the annual CO2 emission 

performance rates applicable to stationary 

combustion turbines in all three interconnections 

are the annual emission rates achievable by that 

subcategory in the Texas Interconnection for years 

from 2022 to 2026, and in the Eastern 

Interconnection for years from 2027 to 2030, 

through application of the building blocks. 

Additional information is provided in the CO2

Emission Performance Rate and State Goal 

Computation TSD in the docket. 

the long-term need to continue reducing 

CO2 emissions beyond the reductions 

that will be achieved through this rule. 

New generating assets are planned and 

built for long lifetimes—frequently 40 

years or more—that are likely longer 

than the expected remaining lifetimes of 

the steam EGUs whose CO2 emissions 

would initially be displaced be the 

generation from the new NGCC units. 

The new capacity is likely to continue 

to emit CO2 throughout these longer 

lifetimes, absent decisions to retire the 

units before the end of their planned 

lifetimes or to install CCS technology in 

the future at substantial additional cost. 

Because of the likelihood of CO2

emissions for decades, the overall net 

emission reductions achievable through 

the construction and operation of new 

NGCC are less than for the measures 

including in the BSER, such as 

increased generation at existing NGCC 

capacity, which would be expected to 

reach the end of its useful life sooner 

than new NGCC capacity, or 

construction and operation of zeroemitting RE generating capacity. We 

view the production of long-term CO2

emissions that otherwise would not be 

created as inconsistent with the BSER 

requirement that we consider the 

magnitude of emissions reductions that 

can be achieved. For this reason, we are 

not including replacement of generation 

from affected EGUs through the 

construction and operation of new 

NGCC capacity in the final BSER. 

Commenters also raised a concern 

with the interrelation of section 111(b) 

and section 111(d). New NGCC capacity 

is distinguished from the other nonBSER measures discussed above by the 

fact that its CO2 emissions would be 

subject to the CO2 standards for new 

EGUs being established under section 

111(b). Section 111 creates an express 

distinction between the sources subject 

to section 111(b) and the sources subject 

to section 111(d), and commenters 

expressed concern that to allow section 

111(b) sources to play a direct role in 

setting the BSER under section 111(d) 

would be inconsistent with 

congressional intent to treat the two sets 

of sources separately. Section VIII of 

this preamble includes a discussion of 

ways to address new NGCC capacity in 

the context of different types of section 

111(d) plans. 

(c) Increasing demand-side EE to 

avoid generation and emissions from 

fossil fuel-fired EGUs. 

The final category of approaches for 

reducing generation and CO2 emissions 

from affected EGUs that the EPA 

considered in the proposal involves 

increasing demand-side EE. When 

demand-side EE is increased, energy 

consumers need less electricity in order 

to provide the same level of electricitydependent services—e.g., heating, 

cooling, lighting, and use of motors and 

electronic devices. Through the 

integrated electricity system, including 

the connection of customers to affected 

EGUs through the electricity grid, 

reduced demand for electricity, in turn, 

leads to reduced generation and reduced 

CO2 emissions. Our examination of 

actions and trends underway in the 

utility power sector confirmed that 

investments in demand-side EE 

programs are increasing. We proposed 

to include avoidance of defined 

quantities of fossil fuel-fired generation 

through increased demand-side EE as a 

component of the BSER (proposed 

building block 4). However, we also 

took comment on which building blocks 

should comprise the BSER and on our 

determination as to whether each 

building block met the various statutory 

factors. 

Commenters expressed a wide range 

of views on the proposed reliance on 

demand-side EE in the BSER. Some 

commenters strongly supported the 

proposal, with suggestions for 

improvements, while some commenters 

strongly opposed the proposal and took 

the position that it exceeded the EPA’s 

legal authority. We do not address the 

merits of these comments here because, 

for the reasons discussed in section 

V.B.3.c.(8) below, we are not finalizing 

the proposal to include avoided 

generation achieved through demandside EE as a component of the BSER. 

However, we note that most 

commenters also supported the use of 

demand-side EE for compliance whether 

or not it is used in determining the 

BSER, and we are allowing demand-side 

EE to be used for that purpose. (We also 

emphasize that the emission limitations 

reflective of the BSER are achievable 

even if aggregate generation is not 

reduced through demand-side EE.) 

(3) Further analysis to quantify the 

BSER. 

While the discussion above 

summarizes how and why the 

components of the BSER were 

determined in terms of qualitative 

characteristics, it still leaves a wide 

range of potential stringencies for the 

BSER. As explained in sections V.C., 

V.D., and V.E. below, discussing 

building blocks 1, 2, and 3 respectively, 

the EPA has determined a reasonable 

level of stringency for each of the 

building blocks rather than the 

maximum possible level of stringency. 

We have taken this approach in part to 

ensure that there is ‘‘headroom’’ within 

the BSER measures that provides greater 

assurance of the achievability of the 

BSER for the source category and for 

individual sources. We believe this 

approach is permissible under the CAA. 

Another aspect of our methodology for 

computing the CO2 emission 

performance rates, further described in 

section V.A.3.f. and section VI, is that 

the CO2 emission performance rate 

applicable to a given source subcategory 

in all three interconnections reflects the 

emission rate achievable by that source 

subcategory through application of the 

building blocks in the interconnection 

where that achievable emission rate is 

the highest (i.e., least stringent).374 This 

aspect of our methodology not only 

ensures that the nationwide CO2

emission performance rates are 

achievable by affected EGUs in all three 

interconnections but also provides 

additional headroom within the BSER 

for affected EGUs in the two 

interconnections that did not set the 

CO2 emission performance rates 

ultimately used. Additional headroom 

within the BSER is available through the 

use of emissions trading approaches, 

because the final rule does not limit the 

use of these mechanisms to sources 

within the same interconnections. In 

fact, in response to proposals that 

emerged from the comment record and 

direct engagement with states and 

stakeholders reflecting their strong 

interest in pursuing multi-state 

approaches, the guidelines include 

mechanisms for implementing 

standards of performance that 

incorporate interstate trading, as 

discussed in section VIII. (In addition, 

as further discussed below, the rule also 

permits section 111(d) plans to allow 

the use of non-BSER measures for 

compliance in certain circumstances, 

increasing both compliance flexibility 

and the assurance that the emission 

limitations reflecting application of the 

BSER are achievable.) 

Further, the sets of measures in each 

of these individual building blocks, in 

the stringency assigned in this rule, 

meet the criteria for the BSER. That is, 

they each achieve the appropriate level 

of reductions, are of reasonable cost, do 

not impose energy penalties on the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64731 

375Criteria for issuance of valid ERCs and for 

tracking credits after issuance are discussed in 

section VIII below. 

affected EGUs and do not result in nonair quality pollutants, and have 

acceptable cost and energy implications 

on a source-by-source basis and for the 

energy sector as a whole. In addition, as 

explained below, each is adequately 

demonstrated. Importantly, past 

industry practice and current trends 

strongly support each of the building 

blocks, as do federal and state pollution 

control programs that require or result 

in similar measures. 

For example, all of the measures in 

building blocks 2 and 3 have been 

implemented for decades, initially for 

reasons unrelated to pollution control, 

then in recent years in order to control 

non-GHG air pollutants, and more 

recently, for purposes of CO2-emission 

control by states and companies. 

Moreover, Congress itself recognized in 

enacting the acid rain provisions of 

CAA Title IV that RE measures reduce 

CO2 from affected EGUs. In addition, the 

EPA has relied on the measures in 

building blocks 2 and 3 in other rules. 

It should also be noted that building 

blocks 2 and 3 also meet the criteria for 

the BSER in combination with one 

another and with building block 1, as 

described below. 

e. Actions that individual affected 

EGUs could take to apply or implement 

the building blocks. We now turn to a 

summary of measures or actions that 

individual EGUs could take to apply or 

implement the building blocks and that 

are therefore, in that sense, part of the 

BSER. 

(1) Improvement in CO2 emission rate 

at the unit. 

An affected EGU may take steps to 

improve its CO2 emission rate as 

discussed above for the source category 

as a whole. As discussed in section V.C., 

the record makes clear that coal-fired 

steam EGUs can make, and have made, 

heat rate improvements to a greater or 

lesser degree, resulting in reductions in 

CO2 emissions. The resulting 

improvement in an EGU’s CO2 emission 

rate would help the EGU achieve an 

emission limit imposed in the form of 

an emission rate. If the EGU’s emission 

limit is imposed in the form of a mass 

standard, the heat rate improvement 

would also lower the EGU’s mass 

emissions provided that the EGU held 

the amount of its generation constant or 

increased its generation by a smaller 

percentage than the efficiency 

improvement. Under a mass-based 

standard that incorporates emission 

trading, an EGU that improves its heat 

rate would need fewer emission 

allowances for each MWh of generation 

whatever level of generation it chose to 

produce. 

(2) Actions to implement measures in 

building blocks 2 and 3. 

Viewing the BSER from the 

perspective of an individual EGU, there 

are several ways that affected EGUs can 

access the measures in building blocks 

2 and 3, thanks to the integrated nature 

of the electricity system, coupled with 

the system’s high degree of planning 

and reliability mechanisms. The 

affected EGUs can: (a) Invest in loweror 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 incentivize 

investment in, the measures in the 

building blocks elsewhere in the 

integrated system; or (c) both invest in 

the measures in the building blocks and 

reduce their own generation, effectively 

replacing their generation with cleaner 

generation. The availability of these 

options is further enhanced where the 

individual EGU is operating under a 

standard of performance that 

incorporates emissions trading. 

(a) Investment in measures in building 

blocks 2 and 3. 

An affected EGU may take the 

following actions to invest in the 

measures in building blocks 2 and 3. For 

building block 2, the owner/operator of 

a steam EGU may increase generation at 

an existing NGCC unit it already owns, 

or one that it purchases or invests in. In 

addition, the owner/operator may, 

through a bilateral transaction with an 

existing NGCC unit, pay the unit to 

increase generation, and acquire the 

CO2-reducing effects of that increased 

generation in the form of a credit, as 

discussed below. 

Similarly, for building block 3, an 

owner/operator of an affected EGU may 

build, or purchase an ownership interest 

in, new RE generating capacity and 

acquire the CO2-reducing effects of that 

increased generation. Alternatively, an 

owner/operator may, through bilateral 

transactions, purchase the CO2-reducing 

effects of that increased generation from 

renewable generation providers, again, 

in the form of a credit. 

In case of an investment in either 

building block 2 or building block 3 by 

a unit subject to a rate-based form of 

CO2 performance standard, it would be 

reasonable for state plans to authorize 

affected EGUs to use an approved and 

validated instrument such as an 

‘‘emission rate credit’’ (ERC) 

representing the emissions-reducing 

benefit of the investment.375

When combined with reduced 

generation, either at the affected EGU or 

elsewhere in the interconnected system, 

the types of actions listed above would 

be fully equivalent to building blocks 2 

and 3 when viewed from the 

perspective of the overall source 

category. Thus, a source could achieve 

a standard of performance identical to 

the applicable CO2 emission 

performance rate in the EPA emission 

guidelines, through implementation of 

the actions described above for building 

blocks 2 and 3, along with the actions 

described further above for building 

block 1. 

The EPA anticipates that in instances 

where section 111(d) plans provide for 

the use of instruments such as ERCs as 

a mechanism to facilitate use of these 

measures, organized markets will 

develop so that owner/operators of 

affected EGUs that have invested in 

measures eligible for the issuance of 

ERCs will be able to sell those credits 

and other affected EGUs will be able to 

purchase them. Such markets have 

developed for other instruments used 

for emissions trading purposes. For 

example, liquid markets for SO2

allowances developed rapidly following 

the implementation of Title IV of the 

1990 Clean Air Act Amendments 

establishing the Acid Rain Program. 

Members of Congress and industry had 

expressed concern during the legislative 

debate that the lack of a liquid SO2

allowance market would create 

challenges for affected sources that 

needed to acquire allowances to meet 

their compliance obligations. Congress 

added statutory provisions to ensure 

that, should a market not develop, 

sources could purchase needed 

allowances directly from the EPA. In 

fact, these provisions went unused 

because a liquid market for allowances 

did develop very quickly. Sources 

engaged in allowance transactions 

directly with other sources as they 

sought to lower compliance costs. 

Market intermediaries offered services 

to sources to match allowance buyers 

and sellers and helped sources 

understand their compliance options. 

Trade associations worked with 

members to develop standardized 

contracts and other tools to facilitate 

allowance transactions, thereby 

reducing transaction costs. Similar 

developments have occurred in stateVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00071 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

tkelley on DSK3SPTVN1PROD with BOOK 2
64732 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

376The emergence of markets under the Acid 

Rain Program and other environmental programs 

where trading has been permitted, as well as state 

and industry support for the development of 

markets under states’ section 111(d) plans, is 

discussed in a recent report by the Advanced 

Energy Economy Institute. AEE Institute, Markets 

Drive Innovation—Why History Shows that the 

Clean Power Plan Will Stimulate a Robust Industry 

Response (July 2015), available at https://

www.aee.net/aeei/initiatives/epa-111d.html#epareports-and-white-papers. 

377There is a theoretical possibility—which we 

view as extremely unlikely—that the affected EGUs 

in a given state or group of states that has chosen 

to pursue a technology-specific rate-based approach 

could have insufficient access to ERCs because of 

the choices of certain other states to pursue massbased or blended-rate approaches. We view this as 

very unlikely in part because of the conservative 

assumptions used in calculating the emission 

reductions available through the building blocks 

and the broad availability of non-BSER emission 

reduction opportunities, such as energy efficiency, 

that will generate ERCs. If such a situation arises, 

and the state or states implementing the technologyspecific rates does not have, within the state or 

states, sufficient ERC-generation potential to match 

their compliance requirements, the EPA will work 

with the state or states to ensure that there is a 

mechanism that the state or states can include in 

their state plans to allow the affected EGUs in the 

state or states to generate additional ERCs where the 

state or states can demonstrate that the ERCs do not 

represent double-counting under other state 

programs. One potential mechanism would be to 

assume for purposes of demonstrating compliance 

with their standards of performance that the 

generation replacing any reductions in generation at 

those affected EGUs that was not paired with 

verified ERCs came from existing NGCC units in 

other states from which ERCs were not accessible. 

In other words, any reductions in fossil steam 

generation from 2012 levels in a state or states that 

was implementing technology-specific rates that 

could not be matched by increases in NGCC 

generation or by ERCs from zero-emitting sources, 

and for which it could be demonstrated that no 

further ERCs can be procured, could generate 

building block 2 ERCs as if that level of displaced 

generation were NGCC generation. A demonstration 

that no further ERCs are procurable would have to 

include demonstrations that the capacity factor of 

all NGCC generation in the state or states was 

expected to be greater than 75 percent and that 

further deployment of RE would go beyond the 

amounts found available in the BSER. States could 

distribute these additional ERCs to ensure 

compliance by affected EGUs. Before such ERCs 

could be created by a state or states, a framework 

would have to be submitted to the EPA for approval 

including documentation of the levels of fossil 

steam and NGCC generation in the state or states, 

a demonstration that no further ERCs are accessible, 

and the total amount of building block 2 ERCs to 

be created. 

378For 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. 

level renewable portfolio standard 

programs.376

If states choose to allow through their 

section 111(d) plans mechanisms or 

standards of performance involving 

instruments such as ERCs, the EPA 

believes that there would be an ample 

supply of such credits, for several 

reasons. First, as discussed in sections 

V.D. and V.E., the EPA has established 

the stringencies for building blocks 2 

and 3 at levels that are reasonable and 

not at the maximum achievable levels, 

providing headroom for investment in 

the measures in these building blocks 

beyond the amounts reflected in the CO2

emission performance rates reflecting 

application of the BSER. In addition, if 

emission limits are set at the CO2

emission performance rates, affected 

EGUs in two of the three 

interconnections on average do not need 

to implement the building blocks to 

their full available extent in order to 

achieve their emission limits (because 

the performance rates for each source 

category are the emission rates 

achievable by that source subcategory 

through application of the building 

blocks in the interconnection where that 

achievable emission rate is the highest), 

providing further opportunities in those 

interconnections to generate surplus 

emission reductions that could be used 

as the basis for issuance of ERCs. 

Further, to the extent that section 111(d) 

plans take advantage of the latitude the 

final guidelines provide for states to set 

standards of performance incorporating 

emissions trading on an interstate basis 

among affected EGUs in different 

interconnections, all sources can take 

advantage of the headroom available in 

other interconnections. As a result, 

significant amounts of existing NGCC 

capacity and potential for RE remain 

available to serve as the basis for 

issuance of ERCs for all affected EGUs 

in both source subcategories to rely on 

to achieve their emission limits. 

Because we recognize the ready 

availability to states of standards of 

performance that incorporate emissions 

trading—and because such standards 

can easily encompass interstate 

trading—this rule includes by express 

design a variety of options that states 

and utilities can select to pursue 

interstate compliance regimes that 

mirror the interconnected operation of 

the electricity system. As a result, the 

EPA believes that it is reasonable to 

anticipate that a virtually nationwide 

emissions trading market for 

compliance will emerge, and that ERCs 

will be effectively available to any 

affected EGU wherever located, as long 

as its state plan authorizes emissions 

trading among affected EGUs.377

It should also be noted that although 

in a state that sets emission limits in a 

rate-based form the measures in 

building blocks 2 and 3 can be taken 

into account directly in computations to 

determine whether an individual 

affected EGU has achieved its emission 

limit, in a state that sets emission limits 

in a mass-based form these measures are 

not taken into account directly in 

computations to determine whether an 

individual affected EGU has achieved 

its emission limit. However, by reducing 

generation and therefore CO2 emissions 

from the group of affected EGUs within 

a region, in a state with mass-based 

limits implementation of these measures 

facilitates the ability of the individual 

EGUs within the region to achieve their 

limits by choosing to reduce their own 

generation and emissions. 

(b) Reduced generation. 

In addition, the owner/operator of an 

affected EGU may help itself meet its 

emission limit by reducing its 

generation. If the owner/operator 

reduces generation and therefore the 

amount of its CO2 emissions, then, if the 

affected EGU is subject to an emission 

rate limit, the owner/operator will need 

to implement fewer of the building 

block measures, e.g., buy fewer ERCs, to 

achieve its emission rate; and if the 

affected EGU is subject to a mass 

emission limit, the owner/operator will 

need fewer mass allowances. As 

discussed below, at the levels that the 

EPA has selected for the BSER, reduced 

generation at higher-emitting EGUs does 

not decrease the amount of electricity 

available to the system and end users 

because lower-emitting (or zeroemitting) generation will be available 

from other sources. 

An owner/operator may take actions 

to ensure that it reduces its generation. 

For example, it may accept a permit 

restriction on the amount of hours that 

it generates. In addition or alternatively, 

it may represent the cost of additional 

emission credits or allowances that 

would be required due to incremental 

generation as an additional variable cost 

that increases the total variable cost 

considered when dispatch decisions are 

made for the unit. 

Because of the integrated nature of the 

electricity system, combined with the 

system’s high degree of planning and 

reliability safeguards, as well as the long 

planning horizon afforded by this rule, 

individual affected EGUs can 

implement the building blocks by 

reducing generation to achieve their 

emission performance standards.378

Individual affected steam EGUs can 

reduce their generation in the amounts 

of building blocks 2 and 3, while 

individual affected NGCC units can 

reduce their generation in the amount of 

building block 3. With emission limits 

for the source category as a whole in 

place, the resulting reduction in supply 

of higher-emitting generation will 

incentivize additional utilization of 

existing NGCC capacity, the resulting 

reduction in overall fossil fuel-fired 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64733 

379As an alternative to authorizing trading that 

would still provide a degree of multi-unit 

flexibility, a state could choose in its state plan to 

give an owner of multiple affected EGUs flexibility 

regarding how the owner distributes any credits or 

allowances it acquires among its affected EGUs. 

380Numerous states submitted comments urging 

the EPA to allow states to develop trading 

programs, as suggested in the proposal, including 

interstate trading programs. They include, for 

example, Alabama (EPA should develop and issue 

guidelines that allow options for multi-state plans 

and interstate credit trading programs, comment 

23584), California (EPA should provide flexibility 

for allowance trading programs to be integrated into 

state plans, comment 23433), Hawaii (supports use 

of emission credit trading with other entities to 

achieve compliance, comment 23121), 

Massachusetts (EPA should explore possibility of 

hosting a third-party emissions trading bank that 

can allow states interested in allowance trading to 

plug and play in to a wider, more cost-effective 

market, comment 31910), Michigan (supports 

emissions trading programs, comment 23987), 

Minnesota (develop model trading rule that states 

could incorporate by reference as part of plan and 

automatically be included in multi-state mass 

trading program, comment 23987), North Carolina 

(EPA should examine a system of banking and 

trading for energy efficiency, comment 23542), 

Oregon (EPA should expand the explicit options for 

multi-state plans beyond cap-and-trade, comment 

20678), Washington (supporting trading, comment 

22764), Wisconsin (requesting EPA to develop a 

national trading program, Post-111(d) Proposal 

Questions to EPA WI Questions for 7/16 Hub call). 

In addition, several groups of states supported 

trading programs: Georgetown Climate Center (a 

group of state environmental agency leaders, energy 

agency leaders, and public utility commissioners 

from California, Colorado, Connecticut, Delaware, 

Illinois, Maine, Maryland, Massachusetts, 

Minnesota, New Hampshire, New York, Oregon, 

Rhode Island, Vermont, and Washington) (‘‘We 

believe states should have maximum flexibility to 

determine what kinds of collaborations might work 

for them. These could include submission of joint 

plans, standardized approaches to trading 

renewable or energy efficiency credits. . . . We 

also encourage EPA to help facilitate such interstate 

agreements or multi-state collaborations by working 

with states to either identify or provide a platform 

or framework that states may elect to use for the 

tracking and trading of avoided generation or 

emissions credits due to interstate efficiency or 

renewable energy.’’ comment 23597, at 39–40); 

RGGI (including Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New 

York, Rhode Island, Vermont) (‘‘[E]very serious 

proposal to reduce carbon emissions from EGUs, 

from proposed US legislation to programs in place 

in California and Europe, has identified allowance 

trading as the best approach.’’ Comment 22395 at 

7–8); Western States Center for New Energy 

Economy (including Arizona, California, Colorado, 

Idaho, Montana, Nevada, Oregon, South Dakota, 

Utah, Washington) (‘‘Some degree of RE and EE 

credit trading among states may support 

compliance, even in the absence of a 

comprehensive regional plan. Therefore, EPA 

should support approaches which allow states 

flexibility to allocate credit for these zero-carbon 

resources, along with approaches which allow 

states to reach agreements on the allocation of 

carbon liabilities. This includes ensuring that 

existing tracking mechanisms for renewable energy 

in the West, such as the Western Renewable Energy 

Generation Information System (WREGIS), are 

compatible with the final proposal.’’ Comment 

21787 at 5); Midcontinent States Environmental and 

Energy Regulators (including Arkansas, Illinois, 

Michigan, Minnesota Missouri, Wisconsin) (EPA 

should also provide states with optional . . . 

systems (or system) for tracking emissions, 

allowances, reduction credits, and/or generation 

attributes that states may choose to use in their 

111(d) plans,’’ comment 22535 at 3). 

In addition, trading programs were supported by, 

among others, a group of Attorneys General from 11 

states and the District of Columbia. Comment 25433 

(Attorneys General from New York, California, 

Connecticut, Maine, Maryland, Massachusetts, New 

Mexico, Oregon, Rhode Island, Vermont, 

Washington, District of Columbia, and New York 

City Corporation Counsel). 

Numerous industry commenters also supported 

trading, including Alliant Energy Corporate 

Services, Inc. (comment 22934), Calpine (comment 

23167), DTE Energy (comment 24061), Exelon 

(comment 23428 and 23155), Michigan Municipal 

Electric Association (MMEA) (comment 23297), 

National Climate Coalition (comment 22910), 

Pacific Gas and Electric Company (comment 

23198), Western Power Trading Forum (WPTF) 

(comment 22860). Environmental advocates also 

supported trading, including Clean Air Task Force 

(comment 22612), Environmental Defense Fund 

(comment 23140), Institute for Policy Integrity, New 

York University School of Law (comment 23418). 

generation will incentivize investment 

in additional RE generating capacity, 

and the integrated system’s response to 

these incentives will ensure that there 

will be sufficient electricity generated to 

continue to meet the demand for 

electricity services. 

(c) Emissions trading. 

As described above, viewed from the 

perspective of the source category as a 

whole, it is reasonable for our analysis 

of the BSER to include an element of 

source-category-wide 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 mass-based emission 

allowances. By the same token, viewed 

from the perspective of an individual 

EGU, consideration of the ready 

availability to states of the opportunity 

to establish standards of performance 

that incorporate emissions trading is 

integral to our analysis. Accordingly, 

our assessment of the actions available 

to individual EGUs for achieving 

standards of performance reflecting the 

BSER includes the purchase of ratebased emission credits or mass-based 

emission allowances, because one of the 

things an affected EGU can do to 

achieve its emission limit is to buy a 

credit or an allowance from another 

affected EGU that has over-complied. 

The use of purchased credits or 

allowances would have to be 

authorized, of course, in the purchasing 

EGUs’ states’ section 111(d) plans and 

would have to meet conditions set out 

for such approaches in section VIII 

below. The role of emissions trading in 

the BSER analysis is discussed further 

in section V.A.2.f. below. 

f. The role of emissions trading. In 

making its BSER determination here, the 

EPA examined a number of technologies 

and emission reduction measures that 

result in lower levels of CO2 emissions 

and evaluated each one on the basis of 

the several criteria on which the EPA 

relies in determining the BSER. In 

contrast to section 111(b), however, 

section 111(d)(1) obliges the states, not 

the EPA, to set standards of performance 

for the affected EGUs in order to 

implement the BSER. Accordingly, with 

respect to each measure or control 

strategy under consideration, the EPA 

also evaluated whether or not the states 

could establish standards of 

performance for affected EGUs that 

would allow those sources to adopt the 

measure in question. In this case, the 

EPA identified a host of factors that 

persuaded us that states could— and, in 

fact, may be expected to—establish 

standards of performance that 

incorporate emissions trading.379 These 

wide-ranging factors include (i) the 

global nature of the air pollutant in 

question—i.e., CO2; (ii) the transactional 

nature of the industry; (iii) the 

interconnected functioning of the 

industry and the coordination of 

generation resources at the level of the 

regional grid; (iv) the extensive 

experience that states—and EGUs— 

already have with emissions trading; 

and (v) material in the record 

demonstrating strong interest on the 

part of many states and affected EGUs 

in using emissions trading to help meet 

their obligations.380

The states’ and EGUs’ interest in 

emissions trading is rooted in the wellrecognized benefits that trading 

provides. The experience of multiple 

trading programs over many years has 

shown that some units can achieve 

emission reductions at lower cost than 

others, and a system that allows for 

those lower-cost reductions to be 

maximized is more cost-effective overall 

to the industry and to society. Trading 

provides an affected EGU other options 

besides direct implementation of 

emission reduction measures in its own 

facility or an affiliated facility when 

lower-cost emission reduction 

opportunities exist elsewhere. 

Specifically, the affected EGU can crossinvest, that is, invest in actions at 

facilities owned by others, in exchange 

for rate-based emission credits or massbased 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 wellVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00073 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

tkelley on DSK3SPTVN1PROD with BOOK 2
64734 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

381As discussed in the Legal Memorandum, the 

EPA has promulgated other rulemakings, including 

the transport rulemakings—the NOX SIP Call and 

CAIR, which required states to submit SIPs, and 

CSAPR, which allows SIPs—on the premise of 

interstate emission trading. 

founded conclusion that it is reasonable 

for states to incorporate emissions 

trading in the standards of performance 

they establish for affected EGUs and that 

many, if not all, would do so.381

Whether viewed from the perspective 

of an individual EGU or the source 

category as a whole, emissions trading 

is thus an integral part of our BSER 

analysis. Again, we concluded that this 

is reasonable given the global nature of 

the pollutant, the transactional and 

interconnected nature of this industry, 

and the long history and numerous 

examples demonstrating that, in this 

sector, trading is integral to how 

regulators have established, and sources 

have complied with, environmental and 

similar obligations (such as RE 

standards) when it was appropriate to 

do so given the program objective. The 

reasonableness is further demonstrated 

by the numerous comments (some of 

which are noted above) from industry, 

states, and other stakeholders in this 

rulemaking that supported allowing 

states to adopt trading programs to 

comply with section 111(d) and 

encouraged EPA to facilitate trading 

across state lines through the use of 

trading-ready state plans. The EPA’s 

reliance on trading in its BSER 

determination does not mean, however, 

that states are required to establish 

trading programs (just as states are not 

required to implement the building 

blocks that comprise BSER). Nor does it 

mean that trading is the only 

transactional approach that we could 

have considered in setting the BSER or 

that states could use to effectuate the 

building blocks were they to decide that 

they did not want to take on the 

responsibility of running a trading 

program. Rather, it is simply a 

recognition of the nature of this industry 

and the long history of trading as an 

important regulatory tool in establishing 

regulatory regimes for this industry and 

its reasonable availability to states in 

establishing standards of performance. 

As an initial matter, trading is 

permissible for these emission 

guidelines because CO2 is a global 

pollutant; the location of its emission 

does not affect the location of the 

environmental harm it causes. For CO2, 

it is the total amount of emissions from 

the source category that matters, not the 

specific emissions from any one EGU. 

The fact that trading allows sources to 

shift emissions from one location to 

another does not impede achievement of 

the environmental goal of reducing CO2

pollution. In its character as a pollutant 

whose impacts extend beyond local 

areas, CO2 pollution resembles to some 

extent the regional SO2 pollution that 

Congress chose to address with the 

emissions trading program enacted in 

Title IV of the 1990 CAA Amendments. 

The argument in support of trading 

approaches is even stronger for CO2

pollution, whose adverse effects are 

global rather than merely regional like 

the SO2 emissions contributing to acid 

precipitation. 

Further, as discussed elsewhere in the 

preamble, the utility power sector—and 

the affected EGUs and other generation 

assets that it encompasses—has a long 

history of working on a coordinated 

basis to meet operating and 

environmental objectives, necessitated 

and facilitated by the unique 

interconnectedness and 

interdependence of the sector. That 

history includes joint dispatch for 

economic and reliability purposes, both 

within large utility systems and in 

multi-utility power pools that have 

evolved into RTOs; joint power plant 

ownership arrangements; and long-term 

and short-term bilateral power purchase 

arrangements. More recently, the 

sector’s history also includes emissions 

trading programs designed by Congress, 

the EPA, and the states to address 

regional environmental problems and, 

most recently, climate change. Examples 

of such programs are noted below. 

Essentially, trading does nothing more 

than commoditize compliance, with the 

following two important results 

emerging from that: It reduces the 

overall costs of controls and spreads 

those costs among the entire category of 

regulated entities while providing a 

greater range of options for sources that 

may not want to make on-site 

investments for controlling their 

emissions and may prefer to make the 

same investment, via the purchase of 

the tradable compliance instrument, at 

another generating source. Building 

blocks 2 and 3 entail affected EGUs 

investing in increased generation from 

existing NGCC units and RE. The 

affected EGUs could do so in any 

number of ways, including acquiring 

ownership interests in existing NGCC or 

RE facilities or entering into bilateral 

transactions with the owners of existing 

NGCC facilities or RE sources. As 

discussed elsewhere, it is reasonable to 

expect that these actions can develop 

into discrete, tradable commodities (e.g., 

an ERC) and that liquid markets will 

develop, which would reduce 

transaction costs and allow an affected 

EGU to comply with its emission limits 

by purchasing discrete units in amounts 

tailored closely to its compliance needs. 

The existence of such tradable 

commodities also incentivizes overcompliance by affected EGUs, which 

can then sell their over-compliance in 

the form of ERCs or allowances to other 

affected EGUs. Moreover, as noted 

elsewhere, the opportunity to trade is 

consistent with the EPA’s regional 

approach for the building blocks. 

By the same token, the opportunity to 

trade incentivizes affected EGUs to overcomply with building block 1. Thus, the 

opportunity to trade supports the EPA’s 

assumptions about what an average 

affected EGU can achieve with regards 

to heat rate improvement even if each 

and every affected EGU cannot achieve 

that level of improvement. In addition, 

trading incentivizes affected EGUs to 

consider low-cost, non-BSER methods 

to reduce emissions as well, and, as 

discussed below, there are numerous 

non-BSER methods, ranging from 

implementation of demand-side EE 

programs to natural gas co-firing. 

Trading has become an important 

mechanism for achieving environmental 

goals in the electricity sector in part 

because trading allows environmental 

regulators to set an environmental goal 

while preserving the ability of the 

operators of the affected EGUs to decide 

the best way to meet it taking account 

of the full range of considerations that 

govern their overall operations. For 

example, commenters were concerned 

that because of building block 2, the 

emission guidelines would require state 

environmental regulators to make 

dispatch decisions for the electricity 

markets, a role that state environmental 

regulators do not currently play. 

Although building block 2 entails 

substituting existing NGCC generation 

for steam generation, implementing the 

emission limits that are based in part on 

building block 2 through a trading 

program provides the individual 

affected EGUs with a great deal of 

control over their own generation while 

the industry as a whole achieves the 

environmental goals. For example, 

individual steam generators have the 

option of maintaining their generation 

as long as they acquire additional ERCs. 

Moreover, trading provides a way for 

states to set standards of performance 

that realize the required emissions 

reduction without requiring any form of 

‘‘environmental dispatch’’ because, as 

many existing trading programs have 

shown, monetization of the 

environmental constraint is consistent 

with a least-cost dispatch system. 

Trading also supports the EPA’s 

approach to the ‘‘remaining useful life’’ 

provision in section 111(d)(1) because 

with trading, an affected EGU with a 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64735 

382For example, in CSAPR, which covered the 

states in the eastern half of the U.S., the EPA 

assumed the existence of trading across those states 

in the rule’s cost estimates contained in the RIA. 

‘‘Regulatory Impact Analysis for the Federal 

Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone in 

27 States; Correction of SIP Approvals for 22 

States’’ 32 (June 2011), http://www.epa.gov/

airtransport/CSAPR/pdfs/FinalRIA.pdf. In addition, 

the rule is being implemented either through 

federal implementation plans (FIPs) that authorize 

interstate emission trading or SIPs that authorize 

interstate emissions trading. 

383Although 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 HAP that caused 

adverse local impacts. 

limited remaining useful life can avoid 

the need to implement long-term 

emission reduction measures and can 

instead purchase ERCs or other tradable 

instruments, such as mass-based 

allowances, thereby allowing the state to 

meet the requirements of this rule. 

The EPA’s job in issuing these 

emission guidelines is to determine the 

BSER that has been adequately 

demonstrated and to set emission 

limitations that are achievable through 

the application of the BSER and 

implementable through standards of 

performance established by the states. 

The three building blocks are the EPA’s 

determination of what technology is 

adequately demonstrated. We also 

consider trading an integral part of the 

BSER analysis because, in addition to 

being available to states for 

incorporation in the standards of 

performance they set for affected EGUs, 

trading has been adequately 

demonstrated for this industry in 

circumstances where systemic rather 

than unit-level reductions are central. 

Congress, the EPA, and state regulators 

have established successful 

environmental programs for this 

industry that allow trading of 

environmental (or similar) attributes, 

and trading has been widely used by the 

industry to comply with these programs. 

Examples include the CAA Title IV 

Acid Rain Program, the NOX SIP Call 

(currently referred to as the NOX Budget 

Trading Program), the Clean Air 

Interstate Rule (CAIR), the Cross-State 

Air Pollution Rule (CSAPR),382 the 

Regional Haze trading programs, the 

Clean Air Mercury Rule,383 RGGI, the 

trading program established by 

California AB32, and the South Coast 

Air Quality Management District 

RECLAIM program. We describe these 

programs in section II.E. of this 

preamble. In addition, we note in the 

Legal Memorandum accompanying this 

preamble that Congress, in enacting the 

Title IV acid rain trading program, and 

the EPA, in promulgating the regulatory 

trading programs listed, recognized both 

the suitability of trading for the EGU 

industry and the benefits of trading in 

reducing costs, spreading costs to 

affected EGUs throughout the sector, 

and facilitating the ability of affected 

EGUs to comply with their emission 

limits. In addition, as we discuss in 

section V.E. of this preamble, many 

states have adopted RE standards that 

promote RE through the trading of 

renewable energy certificates (RECs). 

Based on this history, it is reasonable 

for the EPA to determine that states can 

establish standards of performance that 

incorporate trading and, as a result, for 

the purpose of making a BSER 

determination here to evaluate 

prospective emission control measures 

in light of the availability of trading. 

Trading is a regulatory mechanism that 

works well for this industry. The 

environmental attributes in the 

preceding programs (representing 

emissions of air pollutants) are identical 

to or similar in nature to the 

environmental attribute here (CO2

emissions). The markets for RECs show 

that robust markets for RE, in particular, 

already exist. 

Given the benefits of trading and the 

background of multi-unit coordination 

grounded in the nature of the utility 

power sector, it is natural for sources 

and states to look for opportunities to 

apply similar coordination to a regional 

problem such as reduction of CO2

emissions from the sector. As noted 

earlier, the EPA heard this interest 

expressed during the outreach process 

for this rulemaking and saw it reflected 

in comments on the proposal. Emissions 

trading was prominent in these 

expressions of interest; while the 

proposal allowed trading and 

encouraged the development of multistate 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 multiunit compliance approaches makes great 

sense in the context of the industry and 

this pollutant, as does the specific 

preference for trading-ready section 

111(d) plans, and we have made efforts 

in the final rule to accommodate 

trading-ready plans as described in 

section VIII. 

g. Measures that reduce CO2

emissions or CO2 emission rates but are 

not included in the BSER. There are 

numerous other measures that are 

available to at least some affected EGUs 

to help assure that they can achieve 

their emission limits, even though the 

EPA is not identifying these measures as 

part of the BSER. These measures 

include demand-side EE implementable 

by affected EGUs; new or uprated 

nuclear generation; renewable measures 

other than those that are part of building 

block 3, including distributed 

generation solar power and off-shore 

wind; combined heat and power and 

waste heat power; and transmission and 

distribution improvements. In addition, 

a state may implement measures that 

yield emission reductions for use in 

reducing the obligations on affected 

EGUs, such as demand-side EE 

measures not implementable by affected 

EGUs, including appliance standards, 

building codes, and drinking water or 

wastewater system efficiency measures. 

The availability of these measures 

further assures that the appropriate level 

of emission reductions can be achieved 

and that affected EGUs will be able to 

achieve their emission limits. 

h. Ability of EGUs to implement the 

BSER. The EPA’s analysis, based in part 

on observed decades-long behavior of 

EGUs, shows that all types and sizes of 

affected EGUs in all locations are able 

to undertake the actions described as 

the BSER, including investor-owned 

utilities, merchant generators, rural 

cooperatives, municipally-owned 

utilities, and federal utilities. Some may 

need to focus more on certain measures; 

for example, an owner of a small 

generation portfolio consisting of a 

single coal-fired steam EGU may need to 

rely more on cross-investment 

approaches, possibly including the 

purchase of emission credits or 

allowances, because of a lack of 

sufficient scale to diversify its own 

portfolio to include NGCC capacity and 

RE generating capacity in addition to 

coal-fired capacity. As a legal matter, it 

is not necessary that each affected EGU 

be able to implement the BSER, but in 

any event, in this rule, all affected EGUs 

can do so. Since states can reasonably 

be expected to establish standards of 

performance incorporating emissions 

trading, affected EGUs may rely on 

emissions trading approaches 

authorized under their states’ section 

111(d) plans to, in effect, invest in 

building block measures that are 

physically implemented at other 

locations. As discussed above, the EPA’s 

quantification of the CO2 emission 

performance rates in a manner that 

provides headroom within the BSER 

also contributes to the ability of all 


tkelley on DSK3SPTVN1PROD with BOOK 2
64736 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

384For 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. 

385The 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). 

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 

EPA discretion whether to subcategorize 

the sources for purposes of determining 

the BSER. 

As discussed below, each affected 

EGU can achieve the performance rate 

by implementing the BSER, specifically, 

by taking a range of actions—some of 

which depend on features of the section 

111(d) plan chosen by the state, such as 

the choice of rate-based or mass-based 

standards of performance and the choice 

of whether and how to permit emissions 

trading—including investment in the 

building blocks, replaced or reduced 

generation, and purchase of emission 

credits or allowances. Further, in the 

case of a rate-based state plan, several 

other compliance options not included 

in the BSER for this rule are also 

available to all affected EGUs, including 

investment in demand-side EE 

measures. Such compliance options 

may also indirectly help affected EGUs 

achieve compliance under a mass-based 

plan. 

Our approach of subcategorizing 

between steam EGUs and combustion 

turbines is reasonable because building 

blocks 1 and 2 apply only to steam 

EGUs. Moreover, our approach of not 

further subcategorizing as between 

different types of steam EGUs or 

combustion turbines reflects the 

reasonable policy that affected EGUs 

with higher emission rates should 

reduce their emissions by a greater 

percentage than affected EGUs with 

lower emission rates and can do so at a 

reasonable cost using the approaches we 

have identified as the BSER as well as 

other available measures. 

Of course, a state retains great 

flexibility in assigning standards of 

performance to its affected EGUs and 

can impose different emission reduction 

obligations on its sources, as long as the 

overall level of emission limitation is at 

least as stringent as the emission 

guidelines, as discussed below. 

3. Changes From Proposal 

For the BSER determined in this final 

rule, based on consideration of 

comments responding to a broad array 

of topics considered in the proposal, the 

EPA has adopted certain modifications 

to the proposed BSER. In this subsection 

we describe the most important 

modifications, including some that 

relate to individual building blocks and 

some that are more general. Additional 

modifications that relate to individual 

building blocks are discussed in the 

respective sections for those building 

blocks below (sections V.C. through 

V.E.). 

We note that taken together, the 

modifications yield emission reductions 

requirements that commence more 

gradually than the proposed goals but 

are projected to produce greater overall 

annual emission reductions by 2030.384

We also note that the modifications lead 

to requirements that are more uniform 

across states than the proposed state 

goals (consistent with the direction of 

certain alternatives on which we sought 

comment in the proposal), with the final 

requirements generally becoming more 

stringent (compared to the proposal) in 

states with the highest 2012 CO2

emission rates and less stringent in 

states with lower 2012 CO2 emission 

rates. 

a. Interpretations of CAA section 111. 

In the June 2014 proposal, the EPA 

proposed interpretations of section 

111(a)(1) and (d), and applied these 

interpretations to existing fossil fuelfired EGUs.385 Informed by comments, 

the EPA has clarified some of these 

interpretations, and has developed a 

more refined understanding of how 

some of these interpretations should be 

applied. The clarified and more refined 

interpretations replace the proposed 

interpretations. 

Two of these points merit mention 

here. First, the EPA is clarifying in this 

rule that the interpretation of ‘‘system of 

emission reduction’’ does not include 

emission reduction measures that the 

states have authority to mandate 

without the affected EGUs being able to 

implement the measures themselves 

(e.g., appliance standards or building 

codes). In the final rule, we have 

clarified that the components of the 

BSER must be implementable by the 

affected EGUs, not just by the states, and 

we show that all the components of the 

BSER have been demonstrated to be 

achievable on that basis without 

reliance on actions that can be 

accomplished only through government 

mandates. Further discussion of these 

points can be found throughout this 

section on the BSER and the following 

sections on the individual building 

blocks. 

Second, the EPA has adopted a 

combined interpretation of sections 

111(a)(1) and 111(d) that, compared to 

the proposal, better reflects the 

historical interpretations of section 

111(a)(1), which have generally 

supported emissions standards that are 

nationally uniform for sources 

incorporating a given technology, and 

gives less weight to the state-focused 

character of section 111(d), which calls 

for emissions standards to be 

implemented through the development 

of individual state plans. The proposed 

state goals were heavily (although not 

entirely) dependent on the emission 

reduction opportunities available to the 

EGUs in each individual state, and 

because the relative magnitudes of these 

opportunities varied by state, states with 

similar EGU fleet compositions could 

have faced state goals of different 

stringencies, potentially making it 

difficult for multiple states to set the 

same standards of performance for 

affected EGUs using the same 

technologies (assuming the states were 

interested in setting standards of 

performance for their various affected 

EGUs in such a manner). Some 

commenters viewed this potential result 

as inconsistent with section 111(a)(1), 

inequitable, or both. In response, we 

took further comment on these potential 

disparities in the October 30, 2014 

NODA. In this final rule, we are 

obviating those concerns by assessing 

the emission reduction opportunities at 

an appropriate regional scale, consistent 

with alternatives on which we sought 

comment, and using this regional 

information to reformulate the proposed 

emissions standards as nationally 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64737 

386Of course, a source in one state may face 

different requirements than similar sources in other 

states, depending on whether the state adopts the 

state measures approach or, if it adopts the 

emission standards approach, whether it imposes a 

mass limit or an emission rate and, if the latter, at 

what level. 

387 Generation from existing RE capacity will 

continue to make compliance with mass-based 

standards easier to achieve by making the overall 

amount of fossil fuel-fired generation that is 

required to meet the demand for energy services 

lower than it would otherwise be, thereby keeping 

CO2 emissions lower than they would otherwise be. 

uniform emissions standards for the 

emission guidelines.386 National 

uniformity is consistent with prior 

section 111 rulemaking and advances a 

number of other goals central to this 

rulemaking. The methodological 

refinements related to regional 

assessment of emission reduction 

opportunities and the use of uniform 

emissions standards by technology 

subcategory are further discussed below. 

b. Approach to quantification of 

emission reductions from increased RE 

generation. In the June 2014 proposal, 

the EPA described two possible 

approaches for quantifying the amount 

of emission reductions achievable from 

affected EGUs through the use of RE 

generation. The proposed approach 

used information on state RPS 

aggregated at a regional level along with 

historical RE generation data to project 

the amount of RE generation used in 

quantifying the emission reductions 

achievable through the 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 NODA, we sought comment on an 

additional approach of aggregating the 

state-level information to a regional 

level, as suggested by some commenters. 

In this final rule we are adopting a 

combination of these approaches that 

uses historical RE generating capacity 

deployment data aggregated to a 

regional level, supported and confirmed 

by projections of market potential 

developed through a techno-economic 

approach. 

In the June 2014 proposal, RE 

generation was also quantified as 

generation from total—that is, existing 

and new—RE generating capacity, a 

formulation that was consistent with the 

formulation of most RPS, which are 

typically framed in terms of total rather 

than incremental generation. In 

response to the EPA’s request for 

comment on this approach, commenters 

observed that the approach was 

inconsistent with the approach taken for 

other building blocks, and that 

generation from RE generating capacity 

that already existed as of 2012 should 

not be treated as reducing emissions of 

affected EGUs from 2012 levels. As just 

noted, we are not using the RPS-based 

methodology in the final rule, and we 

agree with comments that quantification 

of RE generation on an incremental 

basis is both more consistent with the 

treatment of other building blocks and 

more consistent with the general 

principle that the BSER should 

comprise incremental measures that 

will reduce emissions below existing 

levels, not measures that are already in 

place, even if those in-place measures 

help current emission levels be lower 

than would be the case without the 

measures. The final rule therefore 

defines the RE component of the BSER 

in terms of incremental rather than total 

RE generation.387 Further details 

regarding the final rule’s quantification 

of RE generation are provided in section 

V.E. below. 

c. Exclusion from the BSER of 

emission reductions from use of underconstruction or preserved nuclear 

capacity. In the June 2014 proposal, the 

EPA included in building block 3 

provisions reflecting the ability for 

nuclear generation to replace fossil 

generation and thereby reduce CO2

emissions at affected EGUs. We 

proposed to include in building block 3 

the potential generation from five 

under-construction nuclear generating 

units whose construction had 

commenced prior to the issuance of the 

proposal. In addition, to address the 

potential that some currently operating 

nuclear facilities may shut down prior 

to 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 underconstruction nuclear units, some 

commenters expressed strong 

opposition to the inclusion of this 

generation in the BSER and the setting 

of state goals, stating that inclusion 

would result in very stringent state goals 

for the states where the units are being 

built and that the inclusion of the 

generation in the goals is premature 

because the units’ actual completion 

dates could be delayed. Commenters 

also stated that inclusion of the underconstruction 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 goals for the particular states where 

the units are located would be overly 

stringent either in absolute terms or 

relative to other states, we also 

acknowledge that, in comparison to RE 

generating technology, investments in 

new nuclear units tend to be 

individually much larger and to require 

longer lead times. Also, important 

recent trends evidenced in RE 

development, such as rapidly growing 

investment and rapidly decreasing 

costs, are not as clearly evidenced in 

nuclear generation. We view these 

factors as distinguishing the underconstruction nuclear units from RE 

generating capacity, indicating that the 

new nuclear capacity is likely of higher 

cost and therefore less appropriate for 

inclusion in the BSER. Excluding the 

under-construction nuclear units from 

the BSER, but allowing emission 

reductions attributable to generation 

from the units to be used for compliance 

as discussed below and in section VIII, 

will recognize the CO2 emission 

reduction benefits achievable through 

the significant ongoing commitment 

required to complete these major 

investments. 

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 


tkelley on DSK3SPTVN1PROD with BOOK 2
64738 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

388As 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. 389 79 FR 64543, 64551–52. 

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 zerocarbon generation, as opposed to the 

production of incremental, low- or zerocarbon generation, could reduce CO2

emissions from current levels. 

Accordingly, we have determined not to 

reflect either of the nuclear elements in 

the final BSER. 

Generation from under-construction 

or other new nuclear units and capacity 

uprates at existing nuclear units would 

still be able to help sources meet 

emission rate-based standards of 

performance through the creation and 

use of credits, as noted in section 

V.A.6.b. and section VIII.K.1.a.(8), and 

would help sources meet mass-based 

standards of performance through 

reduced utilization of fossil generating 

capacity leading to reduced CO2

emissions at affected EGUs. However, 

consistent with the reasons just 

discussed for not reflecting preservation 

of existing nuclear capacity in the 

BSER—namely, that such preservation 

does not actually reduce existing levels 

of emissions from affected EGUs—the 

rule does not allow preservation of 

generation from existing or relicensed 

nuclear capacity to serve as the basis for 

creation of credits that individual 

affected EGUs could use for compliance, 

as further discussed in section 

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

d. Exclusion from the BSER of 

emission reductions from demand-side 

EE. The June 2014 proposal included 

demand-side EE measures in building 

block 4 as part of the BSER. The EPA 

took comment on the attributes of each 

of the proposed building blocks, and 

building block 4 was a topic of 

considerable controversy among 

commenters. While many commenters 

recognized demand-side EE as an 

integral part of the electricity system, 

emphasized its cost-effectiveness as a 

means of reducing CO2 emissions from 

the utility power sector, and strongly 

supported its inclusion in the BSER, 

other commenters expressed significant 

concerns. 

As explained in section V.B.3.c.(8) 

below, our traditional interpretation and 

implementation of CAA section 111 has 

allowed regulated entities to produce as 

much of a particular good as they desire 

provided that they do so through an 

appropriately clean (or low-emitting) 

process. While building blocks 1, 2, and 

3 fall squarely within this paradigm, the 

proposed building block 4 does not. In 

view of this, since the BSER must serve 

as the foundation of the emission 

guidelines, the EPA has not included 

demand-side EE as part of the final 

BSER determination. 

It should be noted that commenters 

also took the position that the EPA 

should allow demand-side EE as a 

means of compliance with the 

requirements of this rule, and, as 

discussed in section V.A.6.b. and 

section VIII below, we agree. 

e. Consistent regionalized approach to 

quantification of emission reductions 

from all building blocks. In the June 

2014 proposal, the EPA treated each of 

the building blocks differently with 

respect to the regional scale on which 

the building block was applied for 

purposes of assessing the emission 

reductions achievable through use of 

that building block. Building block 1 

was quantified at a national scale, 

identifying a single heat rate 

improvement opportunity applicable on 

average to all coal-fired steam EGUs. 

Building block 2 was quantified at the 

scale of each individual state, 

considering the amount of generation 

that could be shifted from steam EGUs 

to NGCC units within the state, although 

we solicited comment on considering 

generation shifts at a broader regional 

scale. The RE component of building 

block 3 was quantified at a regional 

scale using RPS information as a proxy 

for RE development potential, and the 

regional results were then applied to 

each state in the region using the state’s 

baseline data; an alternative 

methodology on which we requested 

comment quantified the RE component 

using a techno-economic approach on a 

state-specific basis. In the October 2014 

NODA, we requested comment on using 

a techno-economic approach to quantify 

RE generation potential at a regional 

scale and took broad comment on 

strategies for better aligning the BSER 

with the regionally interconnected 

electrical grid.389 We also solicited 

comment on the appropriate regional 

boundaries or regional structure to 

facilitate this approach. 

For the final rule, with the benefit of 

comments received in response to these 

proposals and alternatives, we have 

adopted a consistent regionalized 

approach to quantification of emission 

reductions achievable through all the 

building blocks. Under this approach, 

each of the building blocks is quantified 

and applied at the regional level, 

resulting in the computation for each 

region of a performance rate for steam 

EGUs and a performance rate for NGCC 

units. For each of the technology 

subcategories, we identify the most 

conservative—that is, the least stringent 

—of the three regional performance 

rates. We then apply these least 

stringent subcategory-specific 

performance rates to the baseline data 

for the EGU fleet in each state to 

establish state goals of consistent 

stringency across the country. (Note that 

the actual state goals vary among states 

to reflect the differences in generation 

mix among states in the baseline year.) 

Further description of the steps in this 

overall process is contained in the 

preamble sections addressing the 

individual building blocks (sections 

V.C., V.D., and V.E.), CO2 emission 

performance rate computation (section 

VI), and state goal computation (section 

VII), as well as the GHG Mitigation 

Measures TSD for the CPP Final Rule 

and the CO2 Emission Performance Rate 

and Goal Computation TSD for the CPP 

Final Rule available in the docket. 

Compared to the more state-focused 

quantification approach selected in the 

proposal, and as recognized in the 

NODA, a regionalized approach better 

reflects the interconnected system 

within which interdependent affected 

EGUs actually carry out planning and 

operations in order to meet electricity 

demand. We have already discussed the 

relevance of the interconnected system 

and the interdependent operations of 

EGUs as factors supporting 

consideration of building blocks 2 and 

3 as elements of the BSER for this 

pollutant and this industry, and these 

same factors support quantifying the 

emission reductions achievable through 

building blocks 2 and 3 on a 

regionalized basis. Because it better 

reflects how the industry works, a 

regionalized approach also better 

represents the full scope of emission 

reduction opportunities available to 

individual affected EGUs through the 

normal transactional processes of the 

industry, which do not stop at state 

borders but rather extend throughout 

these interconnected regions. With 

respect to building block 1, which 

comprises types of emission reduction 

measures that in other rulemakings 

under CAA section 111 would typically 

be evaluated on a nationwide basis, for 

this rule, as discussed in section V.C. 

below, we are quantifying the emission 

reductions achievable through building 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64739 

390The 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. 

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

Electric Power Systems, IEEE Press, at 188 (2d ed. 

2010). 

392For example, the Eastern Interconnection has 

Reliability Standard IRO–006–EAST–1, 

Transmission Loading Relief Procedure for the 

Eastern Interconnection, available at http://

www.nerc.com/files/IRO–006–EAST–1.pdf 

(providing an ‘‘Interconnection-wide transmission 

loading relief procedure (TLR) for the Eastern 

Interconnection that can be used to prevent and/or 

mitigate potential or actual System Operating Limit 

(SOL) and Interconnection Reliability Operating 

Limit (IROL) exceedances to maintain reliability of 

the Bulk Electric System (BES).’’). 

393FERC–NERC, Arizona-Southern California 

Outages on September 8, 2011: Causes and 

Continued 

block 1 on a regional basis in order to 

treat the building blocks consistently 

and to ensure that for each region the 

quantification of the BSER represents 

only as much potential emission 

reduction from building block 1 as our 

analysis of historical data indicates can 

be achieved on average by the affected 

EGUs in that region. 

Characterizing and quantifying the 

measures included in the BSER on a 

regional basis rather than a state-limited 

basis is also appropriate because states 

can establish standards of performance 

that incorporate emissions trading, 

including trading between and among 

EGUs operating in different states, and 

thus provide EGUs the opportunity to 

trade. Emissions trading provides at 

least one mechanism by which owners 

of affected EGUs can access any of the 

building blocks at other locations. With 

emissions trading, an affected EGU 

whose access to heat rate improvement 

opportunities, incremental generation 

from existing NGCC units, or generation 

from new RE generating capacity is 

relatively favorable can overcomply 

with its own standard of performance 

and sell rate-based emission credits or 

mass-based emission allowances to 

other affected EGUs. Purchase of the 

credits or allowances by the other EGUs 

represents 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.390 In determining that 

the appropriate regional level for 

quantification of the BSER was the level 

of the interconnection, the EPA 

considered several factors. First, 

consistent with our goal of aligning 

regulation with the reality of the 

interconnected electricity system, we 

considered the regional scale on which 

electricity is actually produced, 

physically coordinated, and consumed 

in real time—specifically the Eastern, 

Western, and Texas Interconnections. 

The Bulk Power System (BPS) in the 

contiguous U.S. (including adjacent 

portions of Canada and Mexico) consists 

of these three interconnections, which 

are alternating current (AC) power grids 

where power flows freely from 

generating sources to consuming loads. 

These interconnections are separately 

planned and operated; they are 

connected to each other only through 

low-capacity direct current (DC) tie 

lines. Each interconnection is managed 

to maintain a single frequency and to 

maintain stable voltage levels 

throughout the interconnection. 

Physically, each interconnection 

functions as a large pool, where all 

electricity delivered to the electric grid 

flows by displacement over all 

transmission lines in the 

interconnection and must be 

continually balanced with load to 

ensure reliable electricity service to 

customers throughout each 

interconnection. ‘‘Since power flows on 

all transmission paths, it is not 

uncommon to find circumstances in 

which part of a power delivery within 

one balancing area flows on 

transmission lines in adjoining areas, or 

part of a power delivery between two 

balancing areas flows over the 

transmission facilities of a third 

area.’’ 391 The interconnections are the 

‘‘complex machines’’ within which 

EGUs plan, coordinate, and operate, 

manifesting a degree of both long-term 

and real-time interdependence that is 

unique to this industry. We concluded 

that, absent a compelling reason to 

adopt a smaller regional scale for 

evaluation of CO2 emission reduction 

opportunities for the electric power 

sector—which we have not found, as 

discussed below—the interconnections 

should be the regions used for 

evaluation of the BSER for CO2 emission 

reductions from the electric power 

sector because of the fundamental 

characteristics of electricity, the 

industry’s basic interconnected physical 

infrastructure, and the interdependence 

of the affected EGUs within each 

interconnection. 

Second, we considered whether the 

interconnection subregions for which 

various planning and operational 

functions are carried out by separate 

institutional actors would represent 

more appropriate regions than the entire 

interconnnections, and concluded that 

they would not. Interconnection 

planning and management follows the 

NERC functional model, which defines 

subregional areas and regional entities 

within each interconnection for the 

purposes of balancing generation with 

load and ensuring that reliability is 

maintained. While a variety of 

organizations plan and operate these 

subregions, those activities always occur 

in the context of the interconnections, 

and the subregions cannot be operated 

autonomously. The need to maintain 

common frequency and stable voltage 

levels throughout the interconnections 

requires constantly changing flows of 

electricity between the planning and 

operating subregions within each 

interconnection. 

Because each interconnection is a 

freely flowing AC grid, any power 

generated or consumed flows through 

the entire interconnection in real time; 

as a result of this highly interconnected 

nature of the power system, the 

management of generation and load on 

the grid must be carefully maintained. 

This management is carried out 

principally by subregional entities 

responsible for the operation of the grid, 

but this operation must be coordinated 

in real time to ensure the reliability of 

the system. Regional operators must 

coordinate the dispatch of power, not 

only in their own areas, but also with 

the other subregions within the 

interconnection. Although this 

coordination has always been 

important, grid planning and 

management has evolved to be 

increasingly interconnection-wide, 

through the development of larger 

regional entities, such as RTO/ISOs, or 

large-utility dispatch across multiple 

balancing areas. As a result, the fact that 

much of the necessary coordination for 

the interconnections is performed 

regionally on a partially decentralized 

basis (at least in the case of the Eastern 

and Western Interconnections) or occurs 

through the operation of automated 

equipment and the physics of the grid 

does not render the subregions more 

relevant than the interconnections as 

the ultimate regions within which 

electricity supply and demand must 

balance. 

Moreover, some planning and 

standard setting activities are 

undertaken explicitly at the 

interconnection level. For example, 

interconnections also have 

interconnection reliability operating 

limits (IROLs).392 A joint FERC–NERC 

report on the September 8, 2011 

Arizona-Southern California outages 

outlined the importance of IROLs.393


tkelley on DSK3SPTVN1PROD with BOOK 2
64740 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

Recommendations (Apr. 2012), available at http:// 

www.ferc.gov/legal/staff-reports/04–27–2012-fercnerc-report.pdf. 394FERC–NERC, Arizona-Southern California 

Outages on September 8, 2011: Causes and 

Recommendations, at 97 (Apr. 2012), available at 

http://www.ferc.gov/legal/staff-reports/04–27–2012- 

ferc-nerc-report.pdf. 395American Reinvestment and Recovery Act of 

2009, Title IV, Public Law 111–5 (2009). 396Memorandum of Understanding Between the 

U.S. Department of Energy and the Federal Energy 

Regulatory Commission, available at http://

www.ferc.gov/legal/mou/mou-doe-ferc.pdf. 397 DOE, Recovery Act Interconnection 

Transmission Planning, available at http://

energy.gov/oe/services/electricity-policycoordination-and-implementation/transmissionplanning/recovery-act. 398Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public 

Utilities, Order No. 1000, FERC Stats. & Regs. 

¶ 31,323 (2011), order on reh’g, Order No. 1000–A, 

139 FERC ¶ 61,132, order on reh’g, Order No. 1000– 

B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. 

Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 

2014). 

399NERC, Reliability and Market Interface 

Principles, at 1, available at http://www.nerc.com/ 

pa/Stand/Standards/

ReliabilityandMarketInterfacePrinciples.pdf. 

400NERC, Reliability and Market Interface 

Principles, at 1, available at http://www.nerc.com/ 

pa/Stand/Standards/

ReliabilityandMarketInterfacePrinciples.pdf. 

401NERC, Key Players, available at http://

www.nerc.com/AboutNERC/keyplayers/Pages/

default.aspx. 

402WECC, Standards, available at https://

www.wecc.biz/Standards/Pages/Default.aspx (last 

visited July 3, 2015); Texas Reliability Entity, 

Reliability Standards, available at http://

www.texasre.org/standards_rules/Pages/

Default.aspx (last visited July 3, 2015). 

403The NERC glossary defines the Reliability 

Coordinator Information System as the ‘‘system that 

Reliability Coordinators use to post messages and 

share operating information in real time.’’ NERC, 

Glossary of Terms Used in Reliability Standards 

(Apr. 20, 2009), available at http://www.eia.gov/

electricity/data/eia411/nerc_glossary_2009.pdf. 

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

Electric Power Systems, IEEE Press, at 159 (2d ed. 

2010). 

405PJM, Duke Energy Ohio, Inc., and Duke Energy 

Kentucky, Inc., Successfully Integrated Into PJM 

(Jan. 3, 2012), available at http://www.pjm.com/∼/ 

media/about-pjm/newsroom/2012-releases/

20120103-duke-ohio-and-kentucky-integrate-intopjm.ashx. 

406South Region Integration, available at https:// 

www.misoenergy.org/WhatWeDo/

StrategicInitiatives/SouthernRegionIntegration/

Pages/SouthernRegionIntegration.aspx (noting that 

the creation of the MISO South Region ‘‘brought 

over 18,000 miles of transmission, ∼50,000 

The report noted that to ensure the 

reliable operation of the bulk power 

system, entities must identify a plan for 

IROLs to avoid cascading outages. ‘‘In 

order to ensure the reliable operation of 

the BPS, entities are required to identify 

and plan for IROLs, which are SOLs 

that, if violated, can cause instability, 

uncontrolled separation, and cascading 

outages. Once an IROL is identified, 

system operators are then required to 

create plans to mitigate the impact of 

exceeding such a limit to maintain 

system reliability.’’ 394

Congress recognized the significance 

of the three interconnections in the 

American Recovery and Reinvestment 

Act of 2009 (Recovery Act) when it 

provided $80 million in funding for 

interconnection-based transmission 

planning.395 In order to fulfill this 

Congressional mandate, DOE and FERC 

signed a memorandum of understanding 

to enumerate their roles ‘‘for activities 

related to the Resource Assessment and 

Interconnection Planning project funded 

by the American Recovery and 

Reinvestment Act of 2009 (Recovery 

Act). Among the objectives of the 

project is to facilitate the development 

or strengthening of capabilities in each 

of the three interconnections serving the 

contiguous lower forty-eight States, to 

prepare analyses of transmission 

requirements under a broad range of 

alternative futures and develop longterm interconnection-wide transmission 

plans.’’ 396 DOE issued awards to five 

organizations that performed work in 

the Western, Eastern, and Texas 

Interconnections to develop long-term 

interconnection-wide transmission 

expansion plans.397

In Order No. 1000, FERC also took a 

broader regional view of transmission 

planning.398 FERC required each public 

utility transmission provider to 

participate in a regional transmission 

planning process that produces a 

regional transmission plan. FERC also 

required neighboring transmission 

planning regions to coordinate with 

each other. This interregional 

coordination includes identifying 

methods for evaluating interregional 

transmission facilities as well as 

establishing a common method or 

methods of cost allocation for 

interregional transmission facilities. 

In addition to Congressional, DOE, 

and FERC recognition of the importance 

of the three interconnections, NERC also 

considers them to be significant. NERC 

Organizational Standards ‘‘are based 

upon certain Reliability Principles that 

define the foundation of reliability for 

North American bulk electric 

systems.’’ 399 These principles take a 

broad view of electric system reliability, 

considering the reliability of 

interconnected bulk electric systems. 

For example, Reliability Principle 1 

states, ‘‘Interconnected bulk electric 

systems shall be planned and operated 

in a coordinated manner to perform 

reliably under normal and abnormal 

conditions as defined in the NERC 

standards.’’ 400 NERC took a similarly 

broad view of system reliability when it 

delegated its authority to monitor and 

enforce mandatory reliability standards 

to a single Regional Entity in both the 

Western and Texas Interconnections 

(WECC in the West and the Texas 

Reliability Entity in the ERCOT region 

of Texas).401 Moreover, both WECC and 

ERCOT have interconnection-wide 

reliability standards.402 The Eastern 

Interconnection has multiple reliability 

regions with some differences in 

standards, but power flows and 

reliability are managed through a single 

Reliability Coordinator Information 

System that tracks power flows for all 

transmission transactions.403

The importance that Congress, DOE, 

FERC, and NERC each place upon the 

interconnections for electric reliability 

and operational issues is another factor 

supporting our decision to set the 

interconnections as the regional 

boundaries for the establishment of 

BSER. The utilization of the three 

interconnections for both planning and 

reliability purposes is a clear indication 

of the importance that electricity system 

regulators, operators, and industry place 

upon the interconnections. Those 

responsible for the electricity system 

recognize the need to ensure that there 

is a free flow of electricity throughout 

each interconnection such that 

transmission planning and reliability 

analysis are occurring at the 

interconnection level. Further, this 

vigilance with respect to considering 

reliability from an interconnection-wide 

basis recognizes that each of the 

interconnections behaves as a single 

machine where ‘‘outages, generation, 

transmission changes, and problems in 

any one area in the synchronous 

network can affect the entire 

network.’’ 404 By setting the three 

interconnections as the regions for 

purposes of BSER, we are acting 

consistent with the way in which 

planning, reliability, and industry 

experts view the electricity system. 

An additional factor weighing against 

the use of planning or operational 

subregions of the interconnections as 

the regions for our BSER analysis for 

this rule is that the borders of those 

subregions occasionally change as 

planning and management functions 

evolve or as owners of various portions 

of the grid change affiliations. This is 

not a merely theoretical consideration; 

numerous ISO/RTO and other regional 

boundaries have substantially changed 

in recent years. For example, in 2012, 

Duke Energy Ohio and Duke Energy 

Kentucky integrated into PJM.405 The 

following year, in December 2013, 

Entergy and its six utility operating 

companies joined MISO, creating the 

MISO South Region.406 The integration 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64741 

megawatts of generation capacity, and ∼30,000 MW 

of load into the MISO footprint.’’). 

407NERC previously included Entergy and its six 

operating areas as part of the SERC Assessment 

Areas. NERC, 2014 Summer Reliability Assessment 

(May 2014), available at http://www.nerc.com/pa/

RAPA/ra/Reliability%20Assessments%20DL/

2014SRA.pdf. ‘‘MISO now coordinates all RTO 

activities in the newly combined footprint, 

consisting of all or parts of 15 states with the 

integration of Entergy and other MISO South 

entities. This transition has led to substantial 

changes to MISO’s market dispatch, creating the 

potential for unanticipated flows across the 

following systems: Tennessee Valley Authority 

(TVA), Associated Electric Cooperative Inc. (AECI), 

and Southern Balancing Authority.’’ Id. at 7. 

408SPP, FERC approves Integrates System joining 

SPP (Nov. 12, 2014), available at http://

www.spp.org/publications/

FERC%20approves%20IS%20membership.pdf. 

409NREL, Energy Imbalance Market, available at 

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

energy_imbalance.html. 

410CAISO, EIM Company Profiles (May 2015), 

available at http://www.caiso.com/Documents/

EIMCompanyProfiles.pdf. 

411CAISO, Energy Imbalance Market, available at 

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

stakeholderprocesses/energyimbalancemarket.aspx. 

of MISO South correspondingly led to 

changes in NERC’s regional assessment 

areas.407 FERC also recently approved 

the integration of the Western Areas 

Power Administration—Upper Great 

Plains, Basin Electric Power 

Cooperative, and Heartland Consumers 

Power District into SPP.408

Additionally, PacifiCorp and the CAISO 

recently began operating the western 

Energy Imbalance Market (EIM).409

Other entities such as NV Energy, 

Arizona Public Service Co., and Puget 

Sound Energy are planning to 

participate in the EIM in the future.410

The EIM ‘‘creates significant reliability 

and renewable integration benefits for 

consumers by sharing and economically 

dispatching a broad array of 

resources.’’ 411 This history of changing 

regional boundaries leads us to the 

conclusion that selecting smaller 

regional boundaries for purposes of 

setting the BSER would merely 

represent a snapshot of current, 

changeable regional boundaries. As we 

have seen with recent, large-scale 

changes regarding ISO/RTO boundaries 

and NERC reliability assessment areas, 

such regions would likely not stand the 

test of the time, nor would smaller 

regional boundaries accurately reflect 

electricity flows on the grid. The EPA 

believes that the interconnections are 

the most stable and reasonable regional 

boundaries for setting BSER. 

Third, we considered whether 

transmission constraints, and the fact 

that the specific locations of generation 

resources and loads within each 

interconnection clearly matter to grid 

planning and operations, necessitate 

evaluation of the emission reductions 

available from the building blocks at 

scales smaller than the 

interconnections. We concluded that no 

reduction in scale was needed due to 

such constraints. The same industry 

trends that are reflected in the BSER— 

the changing efficiencies and mix of 

existing fossil EGUs and the 

development of RE throughout each 

interconnection—as well as the 

management of the interconnected grid 

as loads are reduced through EE, which 

is not reflected in the final BSER, are 

already driving power system 

development and are being managed 

through interconnection-wide planning, 

coordination and operations, and will 

continue to be managed in that manner 

in the future with or without this rule. 

While electricity supply and demand 

must be balanced in real time in a 

manner that observes all security 

constraints at that point in time, and key 

aspects of that management are carried 

out at a subregional scale, the emissions 

standards established in this rule can be 

met over longer timeframes through 

processes managed at larger geographic 

scales, just as they are today. We believe 

this rule will reinforce these 

developments and help provide a secure 

basis for moving forward. If a local 

transmission constraint requires that for 

reliability reasons a higher-emitting 

resource must operate during a certain 

period of time in preference to a loweremitting resource that would otherwise 

be the more economic choice when all 

costs are considered, nothing in this 

rule prevents the higher-emitting source 

from being operated. If the same 

transmission constraint causes the same 

conditions to occur frequently, the extra 

cost associated with finding alternative 

ways to reduce emissions will provide 

an economic incentive for concerned 

parties to explore ways to relieve the 

transmission constraint. If relieving the 

constraint would be more costly than 

employing alternative measures to 

reduce emissions, the rule allows 

parties to pursue those alternative 

emission reduction measures. 

Accommodation of intermittent 

constraints and evaluation of 

alternatives for relieving or working 

around them have been routine 

operating and planning practices within 

the utility power sector for many years; 

the rule will not change these basic 

economic practices that occur today. 

The 2022–29 schedule for the rule’s 

interim goals and the 2030 schedule for 

the rule’s final goals allow time for 

planning and investment comparable to 

the sector’s typical planning horizons. 

Finally, the EPA also considered 

whether the smaller geographic scales 

on which affected EGUs may typically 

engage in energy and capacity 

transactions necessitate evaluating the 

emission reductions available from the 

building blocks at scales smaller than 

the interconnections, and again 

concluded that a smaller scale was not 

necessary or justified. We first note that 

electricity trading occurs today 

throughout the interconnection through 

RTO/ISO markets and active spot 

markets, often over large areas such as 

RTO/ISOs, or managed over large 

dispatch areas outside RTOs. These 

trades result in interconnection-wide 

changes in flow that are managed in real 

time. Moreover, the exchange of power 

is not limited to these areas. For 

example, RTOs regularly manage flows 

between RTOs, and EGUs near the 

boundaries of RTOs impact multiple 

subregions across the interconnections, 

so that any subregional boundaries that 

might be evaluated for potential 

relevance as trading region boundaries 

will change as conditions and EGU 

choices change, while interconnection 

boundaries will remain stable. 

In addition, the final rule permits 

trading of rate-based emission credits or 

mass-based emission allowances. 

Emission allowances and other 

commodities associated with electricity 

generation activities, such as RECs, 

which, again, represent investments in 

pollution control measures, are already 

traded separately from the underlying 

electric energy and capacity. There is no 

reason that whatever geographic limits 

may exist for electricity and capacity 

transactions by an affected EGU should 

also limit the EGU’s transactions for 

validly issued rate-based emission 

credits or mass-based emission 

allowances. In fact, as discussed below, 

the final rule not only allows national 

trading without regard to the 

interconnection boundaries, but also 

includes a number of options that 

readily facilitate states’ and utilities’ 

very extensive reliance on emissions 

trading. It is appropriate for the rule to 

take this approach, in part, because the 

non-local nature of the impacts of CO2

pollution do not necessitate geographic 

constraints, and in the absence of a 

policy reason to constrain the 

geographic scope of trading, the largest 

possible scope is the most efficient 

scope. 

f. Uniform CO2 emission performance 

rates by technology subcategory. In 

conjunction with the refinements to the 

interpretations of section 111 reflected 

in the final rule, the EPA has refined the 

methodology for applying the BSER to 

the affected EGUs so as to incorporate 

performance rates that are uniform 

across technology subcategories. 


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64742 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

412The Eastern, Western, and Texas 

Interconnections each encompass large and diverse 

populations of EGUs with numerous and diverse 

opportunities to reduce CO2 emissions through 

application of the measures in each of the three 

building blocks. Based on these considerations of 

scale and diversity, we conclude that each of the 

interconnections is sufficiently representative of the 

source subcategories and emission reduction 

opportunities encompassed in the BSER to 

potentially serve as the basis for CO2 emission 

performance rates applicable to the respective 

source subcategories on a nationwide basis. 

413As discussed in section VI and the CO2

Emission Performance Rate and State Goal 

Computation TSD, the emission performance rates 

for each technology subcategory are computed by 

region for each year from 2022 through 2030, and 

the region with the least stringent emission rate for 

a particular subcategory, whose rate therefore is 

used for all three regions, can differ across years. 

In the case of the steam EGU subcategory, the 

nationwide rate for all years is the rate computed 

for the Eastern Interconnection. In the case of the 

NGCC subcategory, the nationwide rate is the rate 

computed for the Texas Interconnection for the 

years from 2022 through 2026 and the rate 

computed for the Eastern Interconnection for the 

years from 2027 through 2030. 

Specifically, the final rule establishes 

a performance rate of 1305 lbs. per net 

MWh for all affected steam EGUs 

nationwide and a performance rate of 

771 lbs. per net MWh for all affected 

stationary combustion turbines 

nationwide. The computations of these 

performance rates and the 

determinations of state goals reflecting 

the performance rates are described in 

sections VI and VII of the preamble, 

respectively. As described above, in its 

proposed rule and NODA, the EPA 

solicited comment on a number of 

proposals to reflect the regional nature 

of the electricity system in the 

methodology for quantifying the 

emission limitations reflective of the 

BSER. At the same time, the EPA also 

consistently emphasized the need for 

strategies to ensure the achievability 

and flexibility of the established 

emission limitations and to increase 

opportunities for interstate and 

industry-wide coordination. This 

modification is consistent with a 

number of comments we received in 

response to those proposals. The 

commenters took the position that the 

proposed state goals varied too much 

among states and unavoidably implied, 

or would inevitably result in, states 

establishing inconsistent standards of 

performance for sources of the same 

technology type in their respective 

states, which in the commenters’ view 

was not appropriate under section 111. 

Having determined to adopt regional 

alternatives for computing the emission 

reductions achievable under each 

building block, the EPA has further 

determined to exercise discretion not to 

subcategorize based on the regions, and 

instead to apply a nationally uniform 

CO2 emission performance rate for each 

source subcategory. Evaluating the 

emission reduction opportunities 

achievable through application of the 

BSER on a broad regionalized basis, 

which is appropriate for the reasons 

discussed above, makes it possible to 

express the degree of emission 

limitation reflecting the BSER as CO2

emission performance rates that are 

uniform for all affected EGUs in a 

technology subcategory within each 

region. However, the goals and 

strategies embodied in the EPA’s 

proposed rule are best effected by 

setting uniform emission performance 

rates nationally and not just regionally, 

as recognized by commenters favoring 

the use of nationally uniform 

performance rates by technology 

subcategory. Nationally uniform 

emission performance rates create 

greater parity among the emission 

reduction goals established for states 

across the contiguous U.S. and increase 

the ability of states and affected EGUs 

to coordinate emission reduction 

strategies, including through the use of 

emission trading mechanisms if states 

choose to allow such mechanisms, 

which we consider likely. 

Having determined that the 

performance rates computed on a 

regional basis merit consideration as 

nationally applicable performance rates, 

we are also determining that the 

objectives of achievability and 

flexibility would best be met by using 

the least stringent of the regional 

performance rates for the three 

interconnections for each technology 

subcategory as the basis for nationally 

uniform performance rates for that 

technology subcategory rather than by 

using the most stringent of the regional 

performance rates.412 Under this 

approach, the CO2 emission 

performance rate reflecting the BSER for 

all steam EGUs is uniform across the 

contiguous U.S., regardless of the state 

or interconnection where the steam 

EGUs are located. While it is true that 

steam EGUs in the Western and Texas 

Interconnections have opportunities to 

implement the measures in the building 

blocks to a greater extent than the steam 

EGUs in the Eastern Interconnection— 

for example, under building block 2, 

they have relatively greater amounts of 

incremental NGCC generation available 

to replace their generation in all years 

for which performance rates were 

computed—we do not conclude that 

this means that the EGUs in all three 

interconnections should be assigned the 

most stringent CO2 emission 

performance rate computed for any of 

the three regions. Applying nationally 

the performance rate computed for the 

interconnection with the lease stringent 

rate ensures that the emission 

limitations are achievable by the 

affected EGUs in all three 

interconnections. The use of a common 

CO2 emission performance rate across 

all of the steam EGUs in all three 

regions also allocates the burdens of the 

BSER equally across the steam EGU 

source subcategory. The same is true for 

the combustion turbine source 

subcategory, even though, in any year 

for which emission performance rates 

are computed, the combustion turbines 

in two of the interconnections have 

relatively greater opportunities to 

replace their generation with generation 

from new RE generating capacity than 

combustion turbines in the third 

interconnection.413

In addition, using the least stringent 

rate provides greater ‘‘headroom’’—that 

is, emission reduction opportunities 

beyond those reflected in the 

performance rates—to affected EGUs in 

the interconnections that do not set the 

nationwide level. This greater 

‘‘headroom’’ provides greater 

nationwide compliance flexibility and 

assurance that the standards set by the 

states based on the emission guidelines 

will be achievable at reasonable cost 

and without adverse impacts on 

reliability. This is because affected 

EGUs in the interconnections that do 

not set the nationwide level have more 

opportunities to directly invest in each 

of the building blocks in their respective 

regions, and affected EGUs in the 

interconnection that does set the 

nationwide level may in effect invest in 

the opportunities in the other 

interconnections through trading. At the 

same time, our approach still represents 

the degree of emission limitation 

achievable through use of an 

appropriately large and diverse set of 

emission reduction opportunities and 

can therefore reasonably be considered 

the ‘‘best’’ system of emission reduction 

for each technology subcategory. 

Our approach in this rulemaking thus 

not only addresses the comments we 

received regarding potentially disparate 

impacts of the approach presented in 

the proposal, it is also generally 

consistent with the approach we have 

taken in other NSPS rulemakings, where 

standards of performance or emission 

guidelines have typically been 

established at uniform stringencies for 

all units in a given source subcategory, 

and where once the best system of 

emission reduction has been identified, 

stringencies are generally set based on 

what is reasonably achievable using that 

system. 


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414As explained in section III.A. above, an Indian 

tribe whose area of Indian country has affected 

EGUs will have the opportunity but not the 

obligation to seek authority to develop and 

implement a section 111(d) plan. If no tribal plan 

is approved, the EPA has the responsibility to 

establish a plan if it determines that such a plan is 

necessary or appropriate. 

415As noted earlier, there are currently no 

affected EGUs in Vermont or the District of 

Columbia. 

Providing each state with a statespecific weighted average rate-based 

goal allows the state to determine how 

the emission reduction requirements 

should be allocated among the state’s 

affected EGUs. We continue to believe 

that, as in the proposal, this is an 

important source of flexibility for states 

in developing their section 111(d) plans. 

Accordingly, in this final rule we are 

providing uniform CO2 emission 

performance rates for each source 

subcategory and also translating those 

rates to state-specific weighted average 

rate-based goals. For additional 

flexibility, we are also translating the 

state-specific rate-based goals into statespecific mass-based goals. Our 

determinations of the emission 

performance rates are described in 

section VI below, and our 

determinations of the rate-based and 

mass-based state goals are described in 

section VII below. 

We note here that the weightedaverage state goals reflect the 

application of the uniform CO2 emission 

performance rates for affected steam 

EGUs and affected NGCC units to the 

respective units in each subcategory in 

each state. Each state goal therefore 

reflects uniform stringency of emission 

reduction requirements with respect to 

affected units in each source 

subcategory, but also reflects the EGU 

fleet composition and historical 

generation specific to that particular 

state. Compared to the computation 

approach reflected in the proposed state 

goals, the revised approach to quantify 

the BSER on a regional basis and to 

translate the results into nationally 

uniform emission performance rates by 

source subcategory results in more 

stringent goals (compared to the 

proposal) for states whose generation 

has historically been most heavily 

concentrated at coal-fired steam EGUs. 

This shift is an expected consequence of 

the use of uniform performance rates by 

source subcategory. At proposal, these 

states’ goals reflected artificial 

assumptions in the selected goal 

quantification methodology that to a 

considerable extent limited their 

emission reduction opportunities based 

on their states’ borders, and the 

proposed goals therefore were less 

stringent in states which had substantial 

coal generation and little local NGCC 

capacity. The final rule more 

realistically recognizes that emission 

reduction opportunities, like other 

aspects of the interconnected electricity 

system, are regional and are not 

constrained by state borders. The final 

rule also reflects the EPA’s emphasis in 

the proposal on ensuring the 

achievability and flexibility of the 

emission guidelines and increasing 

opportunities for interstate and 

industry-wide coordination. We 

consequently apply the same emission 

performance rates to coal-fired units in 

states with heavy reliance on coalfueled generation as we do to coal-fired 

units in other states, which produces 

more stringent state goals than at 

proposal for the states with the highest 

concentrations of coal-fired generation. 

At the same time, the final goals for 

some states are less stringent than their 

proposed goals. For example, a goal 

based on the least stringent regional 

rates is less stringent for some states 

than a goal based on state-specific 

emission reduction opportunities would 

be. Accordingly, the differences among 

the final state goals are generally smaller 

than the differences among the 

proposed state goals. All of the final 

rate-based state goals are necessarily in 

the range bounded by the CO2 emission 

performance rate for NGCC units and 

the CO2 emission performance rate for 

steam EGUs because all of the state 

goals are computed as a weighted 

average of those two performance rates, 

and this range is narrower than the 

range of state goals in the proposal. 

The computations of the uniform CO2

emission performance rates are shown 

in the CO2 Emission Performance Rate 

and Goal Computation TSD for the CPP 

Final Rule. These uniform emission 

performance rates are applicable to the 

states and areas of Indian country 414

located in the contiguous U.S. that have 

affected EGUs.415 We have not in this 

rule applied the uniform emission 

performance rates to Alaska, Hawaii, 

Puerto Rico, or Guam—states and 

territories that have otherwise affected 

EGUs but are isolated from the three 

major interconnections—and will 

determine how to address the 

requirements of section 111(d) with 

respect to these jurisdictions at a later 

time. Further discussion regarding the 

isolated jurisdictions can be found in 

section VII.F. of the preamble. 

g. Establishment of a 2022–2029 

interim compliance period. The June 

2014 proposal separately quantified 

emission limitations applicable to an 

interim 2020–29 period and to the 

period beginning in 2030. The EPA took 

broad comment on this proposed 

timing. Although the proposal provided 

flexibility in the timing with which 

emission reductions could be made over 

the course of the 2020–2029 period in 

order to achieve compliance with the 

emission limitations applicable to that 

interim period, many commenters 

perceived the start of the period as too 

soon and stated that it provided 

insufficient time for planning and 

investments necessary for sources to 

begin implementation activities while 

maintaining reliable electricity supplies. 

The EPA has considered these 

comments and in the final rule has 

established an interim compliance 

period of 2022–2029, providing two 

additional years for planning and 

investment before the start of 

compliance. We are persuaded by 

comments and by our own further 

analysis that this timeframe is 

appropriate and will, in combination 

with the glide path of emission 

reductions reflected in the final building 

blocks and the states’ flexibility to 

define their own paths of emission 

reductions over the interim period (as 

discussed in section VIII), provide 

adequate time for necessary planning 

and investment activities. This will 

enable the final rule’s requirements to 

be implemented in an orderly manner 

while reliability of electricity supplies is 

maintained. Further discussion is 

provided in the sections of the preamble 

addressing the individual building 

blocks (sections V.C., V.D., and V.E.) 

and on electricity system reliability 

(section VIII.G.2.). 

The initial compliance date of 2022, 

coupled with the fact that the 2030 

standard is phased in over the 

subsequent eight years, affords affected 

EGUs the benefit of having an extended 

planning period before they need to 

incur any significant obligations. Where 

needed, states may take the period 

through September 2018 to develop 

their final plans, and affected EGUs will 

be able to work with the states during 

that period to develop compliance 

approaches. States will also have the 

flexibility to select their own emissions 

trajectories in such a way that certain 

emission reduction measures could be 

implemented later in the interim period 

(again, provided that their affected 

EGUs still meet the interim performance 

rates or interim goal over the interim 

period as a whole). As a result, if the 

affected EGUs in those states need to 

incur any expenses before the adoption 

of the final state plans, those expenses 

need not be more than minimal. It is 

worth noting that an earlier state plan 

submission date provides regulated 

sources with more certainty and time to 


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64744 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

416Alabama Power Co., ‘‘Petition for a Certificate 

of Convenience and Necessity,’’ submitted to the 

Alabama Public Service Commission (June 25, 

2015) (petition requests ‘‘a certificate of 

convenience and necessity for the construction or 

acquisition of renewable energy and 

environmentally specialized generating resources 

and the acquisition of rights and the assumption of 

payment obligations under power purchase 

arrangements pertaining to renewable energy and 

environmentally specialized generating resources, 

together with all transmission facilities, fuel supply 

and transportation arrangements, appliances, 

appurtenances, equipment, acquisitions and 

commitments necessary for or incident thereto’’) 

(included in the docket for this rulemaking). See 

Swartz, Kristi, ‘‘Alabama Power plan would 

dramatically boost its renewables portfolio,’’ E&E 

Publishing, July 16, 2015. 

417See memorandum entitled ‘‘Review of Electric 

Utility Integrated Resource Plans’’ (May 7, 2015) 

available in the docket. 

418The determinations of stringency for each 

source subcategory were made independently for 

each year from 2022 through 2030, and in the case 

of the NGCC category, the limiting region changed 

over time. Thus, for the NGCC category, the uniform 

CO2 emission performance rate is based on the 

stringency achievable in the Texas Interconnection 

for the years from 2022 through 2026 and the 

stringency achievable in the Eastern 

Interconnection for the years from 2027 through 

2030. For the steam EGU subcategory, the uniform 

CO2 emission performance rate is based on the 

stringency achievable in the Eastern 

Interconnection in all years. 

plan for compliance, but has no effect 

on the time when compliance must be 

achieved, as the mandatory compliance 

period begins in 2022 for all states. 

Some states that already have 

established programs for limiting CO2

emissions from power plants may adopt 

and submit to the EPA state plans by 

September 6, 2016. In those states, 

sources will already have developed 

compliance approaches to meet state 

law requirements. Other states that 

submit plans by September 6, 2016, may 

be expected to work with their affected 

EGUs to determine a reasonable 

compliance approach, in light of the fact 

that compliance is not required to begin 

until 2022. It is also possible that some 

states will submit neither final state 

plans nor initial submittals by 

September 6, 2016, and that the EPA 

will promulgate federal plans. Sources 

in those states will have more than five 

years to meet their 2022 compliance 

obligations, a lengthy period that will 

afford them the opportunity to plan 

before incurring significant 

expenditures. 

These periods of time are consistent 

with current industry practice in 

changing generation or adding new 

generation. For example, in June 2015, 

Alabama Power Company announced 

plans to acquire 500 MW of RE 

generation over the next six years. This 

amount would make up between four 

and five percent of Alabama Power’s 

generation mix.416 In addition, the study 

of utility IRPs placed in the docket for 

this rulemaking 417 shows that sources 

are able to replace coal-fired generation 

with natural-gas fired generation and 

add incremental amounts of RE (as well 

as take other actions, such as implement 

demand-side EE programs), on a gradual 

basis, after a several-year lead time, over 

an extended period, as provided for 

under the final rule. 

h. Refinements to stringency for 

individual building blocks. For each 

individual building block, the EPA has 

reexamined the data and assumptions 

used at proposal in light of comments 

solicited and has made a number of 

refinements in the final rule based on 

that information. The refinements are 

discussed in the preamble sections for 

each building block (sections V.C., V.D., 

and V.E.) and emission performance rate 

computation (section VI) and in the 

GHG Mitigation Measures TSD for the 

CPP Final Rule and the CO2 Emission 

Performance Rate and Goal 

Computation TSD for the CPP Final 

Rule. As previously noted, viewed in 

terms of projected nationwide emission 

reductions (but not necessarily with 

respect to each individual state), these 

refinements generally tend to make the 

interim goals somewhat less stringent 

than at proposal and the 2030 goals 

somewhat more stringent than at 

proposal. In addition to the changes 

described above, the refinements 

include the following: 

• Use of regional rates ranging from 2.1 

percent to 4.3 percent (rather than 6 percent) 

as the average heat rate improvement 

opportunity achievable by steam units under 

building block 1. 

• Use of 75 percent of summer capacity 

(rather than 70 percent of nameplate 

capacity) as the target capacity factor for 

existing NGCC units under building block 2. 

• Use of updated information from the 

National Renewable Energy Laboratory 

(NREL) on RE costs and potential, and 

revision of the list of quantified RE 

technologies to exclude landfill gas under 

building block 3. 

4. Determination of the BSER 

In this rule, the EPA is finalizing as 

the BSER a combination of building 

blocks 1, 2, and 3, with refinements as 

discussed below. The building blocks 

constitute the BSER from the 

perspective of the source category as a 

whole. Each building block can be 

implemented through standards of 

performance set by the states and 

includes a set of actions that individual 

sources can use to achieve the emission 

limitations reflecting the BSER. These 

actions and mechanisms, which include 

reduced generation and emissions 

trading approaches where the state-set 

standards of performance incorporate 

trading and which may be understood 

as part of the BSER, will be discussed 

below in section V.A.5. Each of the 

building blocks consists of measures 

that the source category and individual 

affected EGUs have already 

demonstrated the ability to implement. 

In quantifying the application of each 

building block, the EPA has identified 

reasonable levels of stringency rather 

than the maximum possible levels. 

As discussed above, one of the 

modifications being made in this rule is 

the establishment of uniform 

performance rates by technology 

subcategory, which enhances the rule’s 

achievability and flexibility and 

facilitates coordination among the states 

and across the industry. However, in the 

first instance, the emission reductions 

achievable through use of the building 

blocks are being evaluated on a regional 

basis that reflects the regional nature of 

the interconnected electricity system 

and the region-wide scope of 

opportunities available for affected 

EGUs to access emission reduction 

measures. The EPA recognizes that the 

emission reduction opportunities under 

these building blocks vary by region 

because of regional differences in the 

existing mix of types of fossil fuel-fired 

EGUs and the available opportunities to 

increase low- and zero-carbon 

generation. Consequently, in order to 

achieve uniform performance rates by 

technology subcategory, while 

respecting these regional differences in 

emission reduction opportunities, we 

have determined that it is reasonable 

not to establish the stringency of the 

BSER separately by region based on the 

maximum emission reduction that 

would be achievable in that region, but 

instead to establish uniform stringency 

across all regions at a level that is 

achievable at reasonable cost in any 

region. Thus, for each technology 

subcategory, the BSER is the 

combination of the elements described 

above at the combined stringency that is 

reasonably achievable in the region 

where the CO2 emission performance 

rates determined to be achievable at 

reasonable cost by the EGUs in that 

subcategory through application of the 

building blocks were least stringent.418

This approach is consistent with the 

EPA’s efforts to enhance the 

achievability and flexibility of the rule 

and to promote interstate and industry 

coordination and reflects the regional 

strategies emphasized in the proposal 

and the NODA. It is also consistent with 

the approach we have taken in other 

NSPS rulemakings, where the degree of 

emission limitation achievable through 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64745 

419For 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 gas-fired 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. 

the application of the BSER for each 

subcategory of affected sources 

generally has been determined not on 

the basis of what is achievable by the 

sources that can reduce emissions most 

easily, but instead on the basis of what 

is reasonably achievable through the 

application of the BSER across a range 

of sources. This approach also provides 

compliance headroom—in addition to 

the headroom provided by our approach 

to setting the stringency for each 

individual building block—for affected 

EGUs in regions where additional 

emission reductions can be achieved at 

reasonable cost, thereby promoting 

nationwide compliance flexibility. 

Further, because we are authorizing 

states to establish standards of 

performance that incorporate trading 

without geographic restrictions, the 

opportunity of affected EGUs to engage 

in emissions trading, to the extent 

allowed under the relevant section 

111(d) plans, ensures the availability of 

additional, lower-cost emission 

reduction opportunities in other regions 

that will also promote compliance 

flexibility and reduce compliance costs. 

As discussed in section XI of the 

preamble and the Regulatory Impact 

Analysis, application of the BSER 

determined as summarized above is 

projected to result in substantial and 

meaningful reductions of CO2

emissions. 

Briefly, the elements of the BSER are: 

Building block 1: Improving heat rate at 

affected coal-fired steam EGUs in 

specified percentages. 

Building block 2: Substituting increased 

generation from existing affected 

NGCC units for generation from 

affected steam EGUs in specified 

quantities. 

Building block 3: Substituting 

generation from new zero-emitting RE 

generating capacity for generation 

from affected EGUs in specified 

quantities. 

a. Building block 1. Building block 

1—improving heat rate at affected coalfired steam EGUs—is a component of 

the BSER with respect to coal-fired 

steam EGUs 419 because the measures 

the affected EGUs may undertake to 

achieve heat rate improvements are 

technically feasible and of reasonable 

cost, and perform well with respect to 

other factors relevant to a determination 

of the ‘‘best system of emission 

reduction . . . adequately 

demonstrated.’’ Building block 1 is a 

‘‘system of emission reduction’’ for 

steam EGUs because owners of these 

EGUs can take actions that will improve 

their heat rates and thereby reduce their 

rates of CO2 emissions with respect to 

generation. 

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 wellestablished practice within the industry 

that is capable of achieving meaningful 

reductions in CO2 emissions at 

reasonable cost, although, as discussed 

earlier, we also conclude that the 

quantity of emission reductions 

achievable through heat rate 

improvement measures is insufficient 

for these measures alone to constitute 

the BSER. Specifically, we have 

determined that an average heat rate 

improvement ranging from 2.1 to 4.3 

percent by all affected coal-fired EGUs, 

depending on the region, is an element 

of the BSER, based on the inclusion of 

those amounts of improvement in the 

three regions, determined through our 

regional analysis. Our analysis and 

conclusions are discussed in Section 

V.C. below and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. 

Additional analysis and conclusions 

with respect to cost reasonableness are 

discussed in section V.A.4.d. below. 

Consideration of other BSER factors 

also favors a conclusion that building 

block 1 is a component of the BSER. For 

example, with respect to non-air health 

and environmental impacts, heat rate 

improvements cause fuel to be used 

more efficiently, reducing the volumes 

of, and therefore the adverse impacts 

associated with, disposal of coal 

combustion solid waste products. By 

definition, heat rate improvements do 

not cause increases in net energy usage. 

Although we are justifying building 

block 1 as part of the BSER without 

reference to technological innovation, 

we also consider technological 

innovation in the alternative, and we 

note that building block 1 encourages 

the spread of more advanced technology 

to EGUs currently using components 

with older designs. 

As noted in the June 2014 proposal, 

the EPA is concerned about the 

potential ‘‘rebound effect’’ associated 

with building block 1 if applied in 

isolation. More specifically, we noted 

that in the context of the integrated 

electricity system, absent other 

incentives to reduce generation and CO2

emissions from coal-fired EGUs, heat 

rate improvements and consequent 

variable cost reductions at those EGUs 

would cause them to become more 

competitive compared to other EGUs 

and increase their generation, leading to 

smaller overall reductions in CO2

emissions (depending on the CO2

emission rates of the displaced 

generating capacity). Unless mitigated, 

the occurrence of a rebound effect 

would reduce the emission reductions 

achieved by building block 1, 

exacerbating the inadequacy of emission 

reductions that is the basis for our 

conclusion that building block 1 alone 

would not represent the BSER for this 

industry. However, we believe that our 

concern about the potential rebound 

effect can be readily addressed by 

ensuring that the BSER also reflects 

other CO2 reduction strategies that 

encourage increases in generation from 

lower- or zero-carbon EGUs, thereby 

allowing building block 1 to be 

considered an appropriate part of the 

BSER for CO2 emissions at affected 

EGUs as long as the building block is 

applied in combination with other 

building blocks. 

b. Building block 2. Building block 

2—substituting generation from less 

carbon-intensive affected EGUs 

(specifically ‘‘existing’’ NGCC units, 

meaning units that were operating or 

had commenced construction as of 

January 8, 2014) for generation from the 

most carbon-intensive affected EGUs—is 

a component of the BSER for steam 

EGUs because generation shifts that will 

reduce the amount of CO2 emissions at 

higher-emitting EGUs and from the 

source category as a whole are 

technically feasible, are of reasonable 

cost, and perform well with respect to 

other factors relevant to a determination 

of the ‘‘best system of emission 

reduction . . . adequately 

demonstrated.’’ Building block 2 is a 

‘‘system of emission reduction’’ for 

steam EGUs because incremental 

generation from existing NGCC units 

will result in reduced generation and 

emissions from steam EGUs, and owners 

of steam EGUs can, and many do, invest 

in incremental generation from NGCC 

units through a variety of possible 

mechanisms. A steam EGU investing in 

incremental generation from NGCC 

units may choose to reduce its own 

generation or may maintain its 

generation level and choose to allow the 

reduction in generation to occur at other 

steam EGUs through the coordinated 

planning and operation of the 

interconnected electricity system. An 


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420For 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. 

affected EGU may also invest in 

emission reductions from building block 

2 through the mechanism of engaging in 

emissions trading where the EGU is 

operating under a standard of 

performance that incorporates trading. 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of CO2 emission 

reductions achievable at high-emitting 

EGUs through generation shifts to 

lower-emitting affected EGUs are 

discussed in Section V.D. below. 

Additional analysis and conclusions 

with respect to cost reasonableness are 

discussed in section V.A.4.d. below. We 

consider generation shifts among the 

large number of diverse EGUs that are 

linked to one another and to customers 

by extensive regional transmission grids 

to be a routine and well-established 

operating practice within the industry 

that is used to facilitate the achievement 

of a wide variety of objectives, including 

environmental objectives, while meeting 

the demand for electricity services. In 

the interconnected and integrated 

electricity industry, fossil fuel-fired 

steam EGUs are able to reduce their 

generation and NGCC units are able to 

increase their generation in a 

coordinated manner through 

mechanisms—in some cases centralized 

and in others not—that regularly deal 

with such changes on both a short-term 

and a longer-term basis. Our analysis 

demonstrates that the emission 

reductions that can be achieved or 

supported by such generation shifts are 

substantial and of reasonable cost. 

Further, both the achievability of this 

building block and the reasonableness 

of its costs are supported by the fact that 

there has been a long-term trend in the 

industry away from coal-fired 

generation and toward NGCC generation 

for a variety of reasons. 

Building block 2 is adequately 

demonstrated as a ‘‘system of emission 

reduction’’ for affected steam EGUs. As 

discussed in section V.B., since the time 

of the 1970 CAA Amendments, the 

utility power sector has recognized that 

generation shifts are a means of 

controlling air pollutants; in the 1990 

CAA Amendments, Congress recognized 

that generation shifts among EGUs are a 

means of reducing emissions from this 

sector; and generation shifts similarly 

have been recognized as a means of 

reducing emissions under trading 

programs established by the EPA to 

implement the Act’s provisions. It is 

common practice in the industry to 

account for the cost of emission 

allowances as a variable cost when 

making security-constrained, cost-based 

dispatch decisions; doing so integrates 

generation shifts into the operating 

practices used to achieve compliance 

with environmental requirements in an 

economical manner. These industry 

trends are further discussed in section 

V.D. Thus, legislative history, regulatory 

precedent, and industry practice 

support interpreting the broad term 

‘‘system of emission reduction’’ as 

including substituting lower-emitting 

generation for higher-emitting 

generation through generation shifts 

among affected EGUs. 

An important additional 

consideration supporting the 

determination that building block 2 is 

adequately demonstrated as a ‘‘system 

of emission reduction’’ is that owners of 

affected steam EGUs have the ability to 

invest in generation shifts as a way of 

reducing emissions. The owner of an 

affected EGU could invest in such 

generation shifts in several ways, 

including by increasing operation of an 

NGCC unit that it already owns or by 

purchasing an existing NGCC unit and 

increasing operation of that unit. 

Increases in generation by NGCC units 

over baseline levels can also serve as the 

basis for creation of CO2 ERCs—that is, 

instruments representing the ability of 

incremental electricity generated by 

NGCC units to cause emission 

reductions at affected steam EGUs, as 

distinct from the incremental electricity 

itself. Again, it is important to note that 

the acquisition of such ERCs represents 

an investment in the actions of the 

facility or facilities whose alteration of 

utilization levels generated the 

emissions rate improvement or 

reduction. In the context of the BSER, 

purchase of instruments representing 

the emissions-reducing benefit of an 

action is simply a medium of 

investment in the underlying emissions 

reduction action. These mechanisms are 

discussed further in section V.A.5. In 

this rule, the EPA is establishing 

minimum criteria for the creation of 

valid ERCs by NGCC units and for the 

use of such ERCs by affected steam 

EGUs for demonstrating compliance 

with emission rate-based standards of 

performance established under state 

plans. The existence of minimum 

criteria will ensure that crediting 

mechanisms are feasible and will 

facilitate the development of organized 

markets to simplify the process of 

buying and selling ERCs. The minimum 

criteria are discussed in section VIII of 

this preamble. 

We note that an affected EGU 

investing in building block 2 to reduce 

emissions may, but need not, also 

choose to reduce its own generation as 

part of its approach for meeting the 

standard of performance assigned to it 

by its state. Through the coordinated 

operation of the integrated electricity 

system, subject to the collective 

emission reduction requirements that 

will be imposed on affected EGUs in 

order to meet the emissions standards 

representing the BSER, an increase in 

NGCC generation will be offset 

elsewhere in the interconnection by a 

decrease in other generation. Because of 

the need to meet the collective emission 

reduction requirements, the decrease in 

generation resulting from that 

coordinated operation is most likely to 

be generation from an affected steam 

EGU. Measures taken by affected EGUs 

that result in emission reductions from 

other EGUs in the source category may 

appropriately be deemed measures to 

implement or apply the ‘‘system of 

emission reduction’’ of substituting 

lower-emitting generation for higheremitting generation. 

Consideration of other BSER factors 

also supports a determination to include 

building block 2 as a component of the 

BSER. For example, we expect that 

building block 2 would have positive 

non-air health and environmental 

impacts. Coal combustion for electricity 

generation produces large volumes of 

solid wastes that require disposal, with 

some potential for adverse 

environmental impacts; these wastes are 

not produced by natural gas 

combustion. The intake and discharge of 

water for cooling at many EGUs also 

carries some potential for adverse 

environmental impacts; NGCC units 

generally require less cooling water than 

steam EGUs.420 With respect to energy 

impacts, building block 2 represents 

replacement of electrical energy from 

one generator with electrical energy 

from another generator that consumes 

less fuel, so the overall energy impact 

should be a reduction in fuel 

consumption by the overall source 

category as well as by individual 

affected coal-fired steam EGUs. 

Although for purposes of this rule we 

consider the incentive for technological 

innovation only in the alternative, we 

note that building block 2 promotes 

greater use of the NGCC technology 

installed in the existing fleet of NGCC 

units, which is newer and more 

advanced than the technology installed 

in much of the older existing fleet of 

steam EGUs. For all these reasons, the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64747 

421For 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 proposed carbon pollution 

standards for new fossil fuel-fired EGUs. 

measures in building block 2 qualify as 

a component of the ‘‘best system of 

emission reduction . . . adequately 

demonstrated.’’ 

It should be observed that, by 

definition of the elements of this 

building block, the shifts in generation 

taking place under building block 2 

occur entirely among existing EGUs 

subject to this rulemaking.421 Through 

application of this building block 

considered in isolation, some affected 

EGUs—mostly coal-fired steam EGUs— 

would reduce their generation and CO2

emissions, while other affected EGUs— 

NGCC units—would increase their 

generation and CO2 emissions. 

However, because for each MWh of 

generation, NGCC units produce fewer 

CO2 emissions than coal-fired steam 

EGUs, the total quantity of CO2

emissions from all affected EGUs in 

aggregate would decrease without a 

reduction in total electricity generation. 

In the context of the integrated 

electricity system, where the operation 

of affected EGUs of multiple types is 

routinely coordinated to provide a 

highly substitutable service, and in the 

context of CO2 emissions, where 

location is not a consideration (in 

contrast with other pollutants), a 

measure that takes advantage of that 

integration to reduce CO2 emissions 

from the overall set of affected EGUs is 

readily understood as a means to 

implement a ‘‘system of emission 

reduction’’ for CO2 emissions at affected 

EGUs even if the measure would 

increase CO2 emissions from a subset of 

those affected EGUs. Indeed, some 

industry participants are already 

moving in this direction for this purpose 

(while other participants are moving in 

the same direction for other purposes). 

Standards of performance that 

incorporate emissions trading can 

facilitate the implementation of such a 

‘‘system’’ and such approaches have 

already been used in the electricity 

industry to address CO2 as well as other 

pollutants, as discussed above. 

c. Building block 3. Building block 

3—substituting generation from 

expanded RE generating capacity for 

generation from affected EGUs—is a 

component of the BSER because the 

expansion and use of renewable 

generating capacity to reduce emissions 

from affected EGUs is technically 

feasible, is of reasonable cost, and 

performs well with respect to other 

factors relevant to a determination of the 

‘‘best system of emission reduction . . . 

adequately demonstrated.’’ Building 

block 3 is a ‘‘system of emission 

reduction’’ for all affected EGUs because 

incremental RE generation will result in 

reduced generation and emissions from 

affected EGUs, and owners or operators 

of affected EGUs can apply or 

implement building block 3 through a 

number of actions. For example, they 

can invest in incremental RE generation 

either directly or through the purchase 

of ERCs. An affected EGU investing in 

incremental RE generation may choose 

to reduce its own generation by a 

corresponding amount or may choose to 

allow the reduction in generation to 

occur at other affected EGUs through the 

coordinated planning and operation of 

the interconnected electricity system. 

An affected EGU can also invest in RE 

generation by means of engaging in 

emissions trading where the EGU is 

operating under a standard of 

performance that incorporates trading. 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of the measures in 

building block 3 are discussed in 

Section V.E. below. Additional analysis 

and conclusions with respect to cost 

reasonableness are discussed in section 

V.A.4.d. below. We consider 

construction and operation of expanded 

RE generating capacity to be proven, 

well-established practices within the 

industry consistent with recent industry 

trends. States are already pursuing 

policies that encourage production of 

greater amounts of RE, such as the 

establishment of targets for procurement 

of renewable generating capacity. 

Moreover, as discussed earlier, markets 

are likely to develop for ERCs that 

would facilitate investment in increased 

RE generation as a means of helping 

sources comply with their standards of 

performance; indeed, markets for RECs, 

which similarly facilitate investment in 

RE for other purposes, are already wellestablished. As noted in Section V.A.5. 

below, an allowance system or tradable 

emission rate system would provide 

incentives for affected EGUs to reduce 

their emissions as much as possible 

where such reductions could be 

achieved economically (taking into 

account the value of the emission 

credits or allowances), including by 

substituting generation from new RE 

generating capacity for their own 

generation, or could provide a 

mechanism, as stated above, for such 

sources to invest in or acquire such 

generation. 

Building block 3 is adequately 

demonstrated as a ‘‘system of emission 

reduction’’ for all affected EGUs. As 

discussed in section II, RE generation 

has been relied on since the 1970s to 

provide energy security by replacing 

some fossil fuel-fired generation. Both 

Congress and the EPA have previously 

established frameworks under which RE 

generation could be used as a means of 

achieving emission reductions from the 

utility power sector, as discussed in 

section V.B. Investment in RE 

generation has grown rapidly, such that 

in recent years the amount of new RE 

generating capacity brought into service 

has been comparable to the amount of 

new fossil fuel-fired capacity. Rapid 

growth in RE generation is projected to 

continue as costs of RE generation fall 

relative to the costs of other generation 

technologies. These trends are further 

discussed in section V.E. Interpretation 

of a ‘‘system of emission reduction’’ as 

including RE generation for purposes of 

this rule is thus supported by legislative 

history, regulatory precedent, and 

industry practice. 

Also supporting the determination 

that building block 3 is adequately 

demonstrated as a ‘‘system of emission 

reduction’’ is the fact that owners of 

affected EGUs have the ability to invest 

in RE generation as a way of reducing 

emissions. As with building block 2, 

this can be accomplished in several 

ways. For example, the owner of an 

affected EGU could invest in new RE 

generating capacity and operate that 

capacity in order to obtain ERCs. 

Alternatively, the affected EGU could 

purchase ERCs created based on the 

operation of an unaffiliated RE 

generating facility, effectively investing 

in the actions at another site that allow 

CO2 emission reductions to occur. These 

mechanisms are discussed further in 

section V.A.5. As with building block 2, 

in this rule the EPA is establishing 

minimum criteria for the creation of 

valid ERCs by new RE generators and 

for the use of such ERCs by affected 

EGUs for demonstrating compliance 

with emission rate-based standards of 

performance established under state 

plans. The existence of minimum 

criteria will ensure that crediting 

mechanisms are feasible and will 

facilitate the development of organized 

markets to simplify the process of 

buying and selling credits. The 

minimum criteria are discussed in 

section VIII of the preamble. 

As with building block 2, an affected 

EGU investing in building block 3 to 

reduce emissions may, but need not, 

also choose to reduce its own generation 

as part of its approach for meeting the 

standard of performance assigned to it 

by its state. Through the coordinated 

operation of the integrated electricity 

system, subject to the collective 

requirements that will be imposed on 

affected EGUs in order to meet the 


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64748 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

emissions standards representing the 

BSER, an increase in RE generation will 

be offset elsewhere in the 

interconnection by a decrease in other 

generation. Because of the need to meet 

the collective requirements, the 

decrease in generation resulting from 

that coordinated operation is most likely 

to be generation from an affected EGU. 

Measures taken by affected EGUs that 

result in emission reductions from other 

sources in the source category may 

appropriately be deemed methods to 

implement the ‘‘system of emission 

reduction.’’ 

The renewable capacity measures in 

building block 3 generally perform well 

against other BSER criteria. Generation 

from wind turbines and solar voltaic 

installations, two common renewable 

technologies, does not produce solid 

waste or require cooling water, a better 

environmental outcome than if that 

amount of generation had instead been 

produced at a typical range of fossil 

fuel-fired EGUs. With respect to energy 

impacts, fossil fuel consumption will 

decrease both for the source category as 

a whole and for individual affected 

EGUs. Although the variable nature of 

generation from renewable resources 

such as wind and solar units requires 

special consideration from grid 

operators to address possible changes in 

operating reserve requirements, 

renewable generation has grown quickly 

in recent years, as discussed above, and 

grid planners and operators have proven 

capable of addressing any consequent 

changes in requirements through 

ordinary processes. The EPA believes 

that planners and operators will be 

similarly capable of addressing any 

changes in requirements due to future 

growth in renewable generation through 

ordinary processes, but notes that in 

addition, the reliability safety valve in 

this rule, discussed in section VIII.G.2, 

will ensure the absence of adverse 

energy impacts. With respect to 

technological innovation, which we 

consider for the BSER only in the 

alternative, incentives for expansion of 

renewable capacity encourage 

technological 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 well-established. The 

combination of the three building blocks 

will achieve greater CO2 emission 

reductions at reasonable costs than 

possible combinations with fewer 

building blocks and will also perform 

better against other BSER factors. We 

therefore find the combination of all 

three building blocks to be the ‘‘best 

system of emission reduction . . . 

adequately demonstrated’’ for reducing 

CO2 emissions at affected EGUs. 

As already discussed, each of the 

individual building blocks generally 

performs well with respect to the BSER 

factors identified by the statute and the 

D.C. Circuit. (The exception, which we 

have pointed out above, is that building 

block 1, if implemented in isolation, 

would achieve an insufficient 

magnitude of emission reductions to be 

considered the BSER.) The EPA expects 

that combinations of the building blocks 

would perform better than the 

individual building blocks. Beginning 

with the most obvious and important 

advantage, combinations of the building 

blocks will achieve greater emission 

reductions than the individual building 

blocks would in isolation, assuming that 

the building blocks are applied with the 

same stringency. Because fossil fuelfired EGUs generally have higher 

variable costs than other EGUs, it will 

generally be fossil fuel-fired generation 

that is replaced when low-variable cost 

RE generation is increased. At the levels 

of stringency determined to be 

reasonable in this rule, opportunities to 

deploy building block 2 to replace 

higher-emitting generation and to 

deploy building block 3 to replace any 

emitting generation are not exhausted. 

Thus, as the system of emission 

reduction is expanded to include each 

of these building blocks, the emission 

reductions that will be achieved 

increase. 

Because the stringency and timing of 

emission reductions achievable through 

use of each individual building block 

have been set based on what is 

achievable at reasonable cost rather than 

the maximum achievable amount, the 

stringency of the combination of 

building blocks is also reasonable, and 

the combination provides headroom and 

additional flexibility for states in setting 

standards of performance and for 

sources in complying with those 

standards to choose among multiple 

means of reducing emissions. 

With respect to the quantity of 

emission reductions expected to be 

achieved from building block 1 in 

particular, the BSER encompassing all 

three building blocks is a substantial 

improvement over building block 1 in 

isolation. As noted earlier, the EPA is 

concerned that implementation of 

building block 1 in isolation not only 

would achieve insufficient emission 

reductions assuming generation levels 

from affected steam EGUs were held 

constant, but also has the potential to 

result in a ‘‘rebound effect.’’ The nature 

of the potential rebound effect is that by 

causing affected steam EGUs to improve 

their heat rates and thereby lower their 

variable operating costs, building block 

1 if implemented in isolation would 

make those EGUs more competitive 

relative to other, lower-emitting fossil 

fuel-fired EGUs, possibly resulting in 

increased generation and higher 

emissions from the affected steam EGUs 

in spite of their lower emission rates. 

Combining building block 1 with the 

other building blocks addresses this 

concern by ensuring that owner/

operators of affected steam EGUs as a 

group would have appropriate 

incentives not only to improve the 

steam EGUs’ efficiency but also to 

reduce generation from those EGUs 

consistent with replacement of 

generation by low- or zero-emitting 

EGUs. While combining building block 

1 with either building block 2 or 3 

should address this concern, the 

combination of all three building blocks 

addresses it more effectively by 

strengthening the incentives to reduce 

generation from affected steam EGUs. 

The combination of all three building 

blocks is also of reasonable cost, for a 

number of independent reasons 

described below. The emission 

reductions associated with the BSER 

determined in this rule are significant, 

necessary, and achievable. As discussed 

in section V.A.1. above, the 

Administrator must take cost into 

account when determining that the 

measures constituting the BSER are 

adequately demonstrated, and the 

Administrator has done so here. Below, 

we summarize information on the cost 

of the building block measures and 

discuss the several independent reasons 

for the Administrator’s determination 

that the costs of the building block 1, 2, 

and 3 measures, alone or in 

combination, are reasonable. In 

considering whether these costs are 

reasonable, the EPA considered the 

costs in light of both the observed and 

projected effects of GHGs in the 

atmosphere, their effect on climate, and 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64749 

422 If an EGU produces less generation output, 

then an improvement in that EGU’s heat rate and 

rate of CO2 emissions per unit of generation 

produces a smaller reduction in CO2 emissions. If 

the investment required to achieve the 

improvement in heat rate and emission rate is the 

same regardless of the EGU’s generation output, 

then the cost per unit of CO2 emission reduction 

will be higher when the EGU’s generation output 

is lower. Commenters have also stated that 

operating at lower capacity factors may cause units 

to experience deterioration in heat rates. 

423The EPA’s cost-effectiveness estimate of $24 

per ton for building block 2 reflects these market 

dynamics. 

424The EPA’s cost-effectiveness estimate of $37 

per ton for building block 3 reflects these market 

dynamics. 

425Notwithstanding the interactive dynamics that 

improve the cost effectiveness of emission 

reductions when building blocks 2 and 3 are 

implemented together, we also consider each of 

these building blocks to be independently of 

reasonable cost, so that either building block 2 or 

Continued 

the public health and welfare risks and 

impacts associated with such climate 

change, as described in Section II.A. 

The EPA focused on public health and 

welfare impacts within the U.S., but the 

impacts in other world regions 

strengthen the case for action because 

impacts in other world regions can in 

turn adversely affect the U.S. or its 

citizens. In looking at whether costs 

were reasonable, the EPA also 

considered that EGUs are by far the 

largest emitters of GHGs among 

stationary sources in the U.S., as more 

fully set forth in section II.B. 

As described in sections V.C. through 

V.E. and the GHG Mitigation Measures 

TSD, the EPA has determined that the 

cost of each of the three building blocks 

is reasonable. In summary, these cost 

estimates are $23 per ton of CO2

reductions for building block 1, $24 per 

ton for building block 2, and $37 per ton 

for building block 3. The EPA estimates 

that, together, the three building blocks 

are able to achieve CO2 reductions at an 

average cost of $30 per ton, which the 

EPA likewise has determined is 

reasonable. The $30 per ton estimate is 

an average of the estimates for each 

building block, weighted by the total 

estimated cumulative CO2 reductions 

for each of these building blocks over 

the 2022–2030 period. While it is 

possible to weight each building block 

by other amounts, the EPA believes that 

weighting by cumulative CO2 reductions 

best reflects the average cost of total 

reduction potential across the three 

building blocks. The EPA considers 

each of these cost levels reasonable for 

purposes of the BSER established for 

this rule. 

The EPA views the weighted average 

cost estimate as a conservatively high 

estimate of the cost of deploying all 

three building blocks simultaneously. 

The simultaneous application of all 

three building blocks produces 

interactive dynamics, some of which 

could increase the cost and some of 

which could decrease the cost 

represented in the individual building 

blocks. For example, one dynamic that 

would tend to raise costs (and whose 

omission would therefore make the 

weighted average understate costs) is 

that the emission reduction measures 

associated with building blocks 2 and 3 

both prioritize the replacement of 

higher-cost generation (from affected 

steam EGUs in the case of building 

block 2 and from all affected EGUs in 

the case of building block 3). The EPA 

recognizes that the increased magnitude 

of generation replacement when 

building blocks 2 and 3 are 

implemented together necessitates that 

some of the generation replacement will 

occur at more efficient affected EGUs, at 

a relatively higher cost; however, this is 

a consequence of the greater emission 

reductions that can be achieved by 

combining building blocks, not an 

indication that any individual building 

block has become more expensive 

because of the combined deployment. 

Also, the EPA recognizes that when 

building block 1 is combined with the 

other building blocks, the combination 

has the potential to raise the cost of the 

portion of the overall emission 

reductions achievable through heat rate 

improvements relative to the cost of 

those same reductions if building block 

1 were implemented in isolation 

(assuming for purposes of this 

discussion that the rebound effect is not 

an issue and that the affected steam 

EGUs would in fact reduce their 

emissions if building block 1 were 

implemented in isolation).422 However, 

we believe that the cost of emission 

reductions achieved through heat rate 

improvements in the context of a threebuilding block BSER will remain 

reasonable for two reasons. First, as 

discussed in section V.C. below, even 

when conservatively high investment 

costs are assumed, the cost of CO2

emission reductions achievable through 

heat rate improvements is low enough 

that the cost per ton of CO2 emission 

reductions will remain reasonable even 

if that cost is substantially increased. 

Second, although under a BSER 

encompassing all three building blocks 

the volume of coal-fired generation will 

decrease, that decrease is unlikely to be 

spread uniformly among all coal-fired 

EGUs. It is more likely that some coalfired EGUs will decrease their 

generation slightly or not at all while 

others will decrease their generation by 

larger percentages or cease operations 

altogether. We would expect EGU 

owners to take these changes in EGU 

operating patterns into account when 

considering where to invest in heat rate 

improvements, with the result that there 

will be a tendency for such investments 

to be concentrated in EGUs whose 

generation output is expected to 

decrease the least. This enlightened bias 

in spending on heat rate 

improvements—that is, focusing 

investments on EGUs where such 

improvements will have the largest 

impacts and produce the highest 

returns, given consideration of projected 

changes in dispatch patterns—will tend 

to mitigate any deterioration in the cost 

of CO2 emission reductions achievable 

through heat rate improvements. 

In contrast with those prior examples, 

combining the building blocks also 

produces interactive dynamics that 

significantly reduce the cost for CO2

reductions represented in the individual 

building blocks (and whose omission 

would therefore make the weighted 

average overstate costs). Foremost 

among these dynamics is the 

stabilization of wholesale power prices. 

When assessed individually, building 

blocks 2 and 3 have opposite impacts on 

wholesale power prices, although in 

each case, the direction of the wholesale 

power price impact corresponds to an 

increasing cost of that building block in 

isolation. For example, building block 2 

promotes more utilization of existing 

NGCC capacity, which (assessed on its 

own) would increase natural gas 

consumption and therefore price, in 

turn raising wholesale power prices 

(which are often determined by gas-fired 

generators as the power supplier on the 

margin); this dynamic puts upward 

pressure on the cost of achieving CO2

reductions through shifting generation 

from steam EGUs to NGCC units.423

Meanwhile, building block 3 increases 

RE deployment; because RE generators 

have very little variable cost, an increase 

in RE generation replaces other supply 

with higher variable cost, which would 

yield lower wholesale power prices. 

Lower wholesale power prices would 

make further RE deployment less 

competitive against generation from 

existing emitting sources; while this 

dynamic would generally reduce 

electricity prices to consumers, it also 

puts upward pressure on the cost of 

achieving CO2 reductions through 

increased RE deployment.424 Applying 

building blocks 2 and 3 together 

produces significantly more CO2

reductions at a relatively lower cost 

because the countervailing nature of 

these wholesale power price dynamics 

mitigates the primary cost drivers for 

each building block.425


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3 alone, or combinations of the building blocks that 

include either but not both of these two building 

blocks, could be the BSER if a court were to strike 

down the other building block, as discussed in 

section V.A.7. below. (We also note in section 

V.A.7. that a combination of building blocks 2 and 

3 without building block 1 could be the BSER if a 

court were to strike down building block 1.) 

426Specifically, at proposal the EPA quantified 

the average cost, in dollar per ton of CO2 reduced, 

of building blocks 1, 2, and 3 ($22.5 per ton) to be 

less than the cost of either building block 2 ($28.9 

per ton) or building block 3 ($23.4 per ton) alone. 

427For details of these computations, see the 

memorandum ‘‘Comparison of building block costs 

to FGD costs’’ available in the docket. 

428The comparison for an NGCC unit considers 

only building block 3 because building blocks 1 and 

2 do not apply to NGCC units. 

429For details of these computations, see the 

memorandum ‘‘Comparison of building block costs 

to FGD costs’’ available in the docket. 

430See Synapse Energy Economics Inc., 2015 

Carbon Dioxide Price Forecast (March 3, 2015) at 

25–28, available at http://www.synapseenergy.com/sites/default/files/2015%20Carbon%20

Dioxide%20Price%20Report.pdf. 

The EPA believes the dynamics 

tending to cause the weighted average 

above to overstate costs of the 

combination of building blocks are 

greater than the dynamics tending to 

cause costs to be understated, and that 

the weighted average costs are therefore 

conservatively high. Analysis performed 

by the EPA at an earlier stage of the 

rulemaking supports this conclusion. At 

proposal, the EPA evaluated the cost of 

increasing NGCC utilization (building 

block 2) and deploying incremental RE 

generation (building block 3) 

independently, as well as the cost of 

simultaneously increasing NGCC 

utilization and incremental RE 

generation. The average cost (in dollars 

per ton of CO2 reduced) was less for the 

combined building block scenario, 

showing that the net outcome of the 

interactivity effects described above is a 

reduction in cost per ton when 

compared to cost estimates that do not 

incorporate this interactivity.426

A final reason why the EPA considers 

the weighted-average cost above 

conservatively high is that simply 

combining the building blocks at their 

full individual stringencies overstates 

the stringency of the BSER. As 

discussed in section V.A.3.f and section 

VI, the BSER reflects the combined 

degree of emission limitation achieved 

through application of the building 

blocks in the least stringent region. By 

definition, in the other two regions, the 

BSER is less stringent than the simple 

combination of the three building blocks 

whose stringency is represented in the 

weighted-average cost above. 

The cost estimates for each of the 

three building blocks cited above—$23, 

$24, and $37 per ton of CO2 reductions 

from building blocks 1, 2, and 3, 

respectively—are each conservatively 

high for the reasons discussed in section 

V.C., V.D., and V.E. below. Likewise, the 

$30 per ton weighted-average cost of all 

three building blocks is a conservatively 

high estimate of the cost of the 

combination of the three individual 

building block costs, as described above. 

While conservatively high, and 

especially so in the case of the $30 per 

ton weighted-average cost, these 

estimates fall well within the range of 

costs that are reasonable for the BSER 

for this rule. 

In assessing cost reasonableness for 

the BSER determination for this rule, 

the EPA has compared the estimated 

costs discussed above to two types of 

cost benchmark. The first type of 

benchmark comprises costs that affected 

EGUs incur to reduce other air 

pollutants, such as SO2 and NOX. In 

order to address various environmental 

requirements, many coal-fired EGUs 

have been required to decide between 

either shutting down or installing and 

operating flue gas desulfurization (FGD) 

equipment—that is, wet or dry 

scrubbers—to reduce their SO2

emissions. The fact that many of these 

EGUs have chosen scrubbers in 

preference to shutting down is evidence 

that scrubber costs are reasonable, and 

we believe that the cost of these controls 

can reasonably serve as a cost 

benchmark for comparison to the costs 

of this rule. We estimate that for a 300– 

700 MW coal-fired steam EGU with a 

heat rate of 10,000 Btu per kWh and 

operating at a 70 percent utilization rate, 

the annualized costs of installing and 

operating a wet scrubber are 

approximately $14 to $18 per MWh and 

the annualized costs of installing and 

operating a dry scrubber are 

approximately $13 to $16 per MWh.427

In comparison, we estimate that for a 

coal-fired steam EGU with a heat rate of 

10,000 Btu per kWh, assuming the 

conservatively high cost of $30 per ton 

of CO2 removed through the 

combination of all three building blocks, 

the cost of reducing CO2 emissions by 

the amount required to achieve the 

uniform CO2 emission performance rate 

for steam EGUs of 1,305 lbs. CO2 per 

MWh would be equivalent to 

approximately $11 per MWh. The 

comparable costs for achieving the 

required emission performance rate for 

steam EGUs through use of the 

individual building blocks range from 

$8 to $14 per MWh. For an NGCC unit 

with a heat rate of 7,800 Btu per kWh, 

assuming a conservatively high cost of 

$37 per ton of CO2 removed through the 

use of building block 3,428 the cost of 

reducing CO2 emissions by the amount 

required to achieve the uniform CO2

emission performance rate for NGCC 

units of 771 lbs. CO2 per MWh would 

be equivalent to approximately $3 per 

MWh.429 These estimated CO2 reduction 

costs of $3 to $14 per MWh to achieve 

the CO2 emission performance rates are 

either less than the ranges of $14 to $18 

and $13 to $16 per MWh to install and 

operate a wet or dry scrubber, or in the 

case of CO2 emission reductions at a 

steam unit achieved through building 

block 3, near the low end of the ranges 

of scrubber costs. This comparison 

demonstrates that the costs associated 

with the BSER in this rule are 

reasonable compared to the costs that 

affected EGUs commonly face to comply 

with other environmental requirements. 

The second type of benchmark 

comprises CO2 prices that owners of 

affected EGUs use for planning purposes 

in their IRPs. Utilities subject to 

requirements to prepare IRPs commonly 

include assumptions regarding future 

environmental regulations that may 

become effective during the time 

horizon covered by the IRP, and 

assumptions regarding CO2 regulations 

are often represented in the form of 

assumed prices per ton of CO2 emitted 

or reduced. A survey of the CO2 price 

assumptions from 46 recent IRPs shows 

a range of CO2 prices in the IRPs’ 

reference cases of $0 to $30 per ton, and 

a range of CO2 prices in the IRPs’ high 

cases from $0 to $110 per ton.430 In 

comparison, the conservatively high, 

weighted-average cost of $30 per ton 

removed described above is at the high 

end of the range of reference case 

assumptions but at the low end of the 

range of the high case assumptions. The 

costs of the individual building blocks 

are likewise well within the range of the 

high case assumptions, and either at or 

slightly above the high end of the 

reference case assumptions. This 

comparison demonstrates that the costs 

associated with the BSER in this rule are 

reasonable compared to the expectations 

of the industry for the potential costs of 

CO2 regulation. 

In addition to comparison to these 

benchmarks, there is a third 

independent way in which EPA has 

considered cost. In light of the severity 

of the observed and projected climate 

change effects on the U.S., U.S. 

interests, and U.S. citizens, combined 

with EGUs’ large contribution to U.S. 

GHG emissions, the costs of the BSER 

measures are reasonable when 

compared to other potential control 

measures for this sector available under 


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431The EPA’s regulatory impact analysis for this 

rule, which appropriately includes a representation 

of the flexibility available under the rule to comply 

using a combination of BSER and non-BSER 

measures (such as demand-side energy efficiency) 

is discussed in section XI of the preamble. 

432See memo entitled ‘‘Consideration of Costs 

and Benefits Under the Clean Air Act’’ available in 

the docket. 

433Estimates are presented in the Technical 

Support Document: Technical Update of the Social 

Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 2013, Revised 

July 2015), Interagency Working Group on Social 

Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental 

Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of 

Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and 

Climate Change, Office of Management and Budget, 

Office of Science and Technology Policy, and 

Department of Treasury (May 2013, Revised July 

2015). Available at: https://www.whitehouse.gov/

sites/default/files/omb/inforeg/scc-tsd-final-july2015.pdf> Accessed 7/11/2015. 

434The SC–CO2 estimates do not include all 

important damages because of current modeling 

and data limitations. The 2014 IPCC report 

observed that SC–CO2 estimates omit various 

impacts that would likely increase damages. See 

IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Contribution of 

Working Group II to the Fifth Assessment Report of 

the Intergovernmental Panel on Climate Change. 

Cambridge University Press, Cambridge. https://

www.ipcc.ch/report/ar5/wg2/. 

435The 2010 and 2013 TSDs present SC–CO2 in 

2007$ per metric ton. The unrounded estimates 

from the current TSD were adjusted to (1) 2011$ 

using GDP Implicit Price Deflator (1.061374), http:// 

www.bea.gov/iTable/index_nipa.cfm and (2) short 

tons using the conversion factor of 0.90718474 

metric tons in a short ton. These estimates were 

rounded to two significant digits. 

section 111. Given EGUs’ large 

contribution to U.S. GHG emissions, any 

attempt to address the serious public 

health and environmental threat of 

climate change must necessarily include 

significant emission reductions from 

this sector. The agency would therefore 

consider even relatively high costs— 

which these are not—to be reasonable. 

Imposing only the lower cost reduction 

measures in building block 1 would not 

achieve sufficient reductions given the 

scope of the problem and EGUs’ 

contribution to it. While the EPA also 

considered measures such as CCS 

retrofits for all fossil-fired EGUs or cofiring at all steam units, the EPA 

determined that these costs were too 

high when considered on a sector-wide 

basis. Furthermore, the EPA has not 

identified other measures available 

under section 111 that are less costly 

and would achieve emission reductions 

that are commensurate with the scope of 

the problem and EGUs’ contribution to 

it. Thus, the EPA determined that the 

costs of the measures in building blocks 

1, 2 and 3, individually or in 

combination, are reasonable because 

they achieve an appropriate balance 

between cost and amount of reductions 

given the other potential control 

measures under section 111. 

As required under Executive Order 

12866, the EPA conducts benefit-cost 

analyses for major Clean Air Act 

rules.431 While benefit-cost analysis can 

help to inform policy decisions, as 

permissible and appropriate under 

governing statutory provisions, the EPA 

does not use a benefit-cost test (i.e., a 

determination of whether monetized 

benefits exceed costs) as the sole or 

primary decision tool when required to 

consider costs or to determine whether 

to issue regulations under the Clean Air 

Act, and is not using such a test here.432

Nonetheless, the EPA observes that the 

costs of the building block 1, 2 and 3 

measures, both individually and 

combined as discussed in this section 

above, are less than the central estimates 

of the social cost of carbon. Developed 

by an interagency workgroup, the social 

cost of carbon (SC–CO2) is an estimate 

of the monetary value of impacts 

associated with marginal changes in 

CO2 emissions in a given year.433 It is 

typically used to assess the avoided 

damages as a result of regulatory actions 

(i.e., benefits of rulemakings that lead to 

an incremental reduction in cumulative 

global CO2 emissions).434 The central 

values for the SC–CO2 range from $40 

per short ton in 2020 to $48 per short 

ton in 2030.435 The weighted-average 

cost estimate of $30 per ton is well 

below this range. 

Finally, the EPA notes that the 

combination of all three building blocks 

would perform consistently with the 

individual building blocks with respect 

to non-air energy and environmental 

impacts. There is no reason to expect an 

adverse non-air environmental or energy 

impact from deployment of the 

combination of the three building 

blocks, whether considered on a sourceby-source basis, on a sector-wide or 

national basis, or both. In fact, the 

combination of the building blocks, like 

the building blocks individually, as 

discussed above, would be expected to 

produce non-air environmental cobenefits in the form of reduced water 

usage and solid waste production (and, 

in addition to these non-air 

environmental co-benefits, would also 

be expected to reduce emissions of nonCO2 air pollutants such as SO2, NOX, 

and mercury). Likewise, with respect to 

technological innovation, which we 

consider only in the alternative, the 

building blocks in combination would 

have the same positive effects that they 

would have if implemented 

independently. 

e. Other combinations of the building 

blocks. The EPA has considered 

whether other combinations of the 

building blocks, such as a combination 

of building blocks 1 and 2 or a 

combination of building blocks 1 and 3, 

could be the BSER. We believe that any 

such combination is technically feasible 

and would be a ‘‘system of emission 

reduction’’ capable of achieving 

meaningful reductions in CO2 emissions 

from affected EGUs at a reasonable cost. 

As with the combination of three 

building blocks discussed above, any 

combination of building blocks would 

achieve greater emission reductions 

than the individual building blocks 

encompassed in that combination 

would achieve if implemented in 

isolation. Further, the cost of any 

combination would be driven 

principally by the combined stringency 

and would remain reasonable in 

aggregate, such that the conclusions on 

cost reasonableness discussed in section 

V.A.4.d. would continue to apply. We 

have already noted our determination 

that building block 1 in isolation is not 

the BSER because it would not produce 

a sufficient quantity of emission 

reductions. A combination of building 

block 1 with one of the other building 

blocks would produce greater emission 

reductions and would not be subject to 

this concern. Any combination of 

building blocks including building 

block 1 and at least one other building 

block would also address the concern 

about potential ‘‘rebound effect,’’ 

discussed above, that could occur if 

building block 1 were implemented in 

isolation. Finally, there is no reason to 

expect any combination of the building 

blocks to have adverse non-air energy or 

environmental impacts, and the 

implications for technological 

innovation, which we consider only in 

the alternative, would likewise be 

positive for any combination of the 

building blocks because those 

implications are positive for the 

individual building blocks and there is 

no reason to expect negative interaction 

from a combination of building blocks. 

For these reasons, any combination of 

the building blocks (but not a BSER 

comprising building block 1 in 

isolation) could be the BSER if it were 

not for the fact that a BSER comprising 

all three of the building blocks will 

achieve greater emission reductions at a 

reasonable cost and is therefore 

‘‘better.’’ As discussed below in section 

V.A.7., we intend for the individual 

building blocks to be severable, such 

that if a court were to deem building 

block 2 or 3 defective, but not both, the 

BSER would comprise the remaining 

building blocks. 

f. Achievability of emission limits. As 

noted, based on the BSER, the EPA has 


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436See Essex Chem. Corp. v. Ruckelshaus, 486 

F.2d 427, 433–34 (D.C. Cir. 1973), cert. denied, 416 

U.S. 969 (1974); Nat’l Lime Ass’n v. EPA, 627 F.2d 

416, 433, n.46 (D.C. Cir. 1980); Sierra Club v. Costle, 

657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l Lime 

Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 

437We discuss the ability of affected EGUs to 

implement the building blocks in more detail in 

sections V.C., V.D., and V.E. and the accompanying 

support documents. 

established a source subcategoryspecific emission performance rate for 

fossil steam units and one for NGCC 

units. As discussed in section V.A.1.c., 

for new sources, standards of 

performance must be ‘‘achievable’’ 

under CAA section 111(a)(1), and the 

D.C. Circuit has identified criteria for 

achievability.436 In this rule, the EPA is 

taking the approach that while the states 

are not required to adopt those source 

subcategory-specific emission 

performance rates as the standards of 

performance for their affected EGUs, 

those rates must be achievable by the 

steam generator and NGCC 

subcategories, respectively. In addition, 

the EPA is assuming that the 

achievability criteria in the case law for 

new sources apply to existing sources 

under section 111(d). For the reasons 

discussed next, for this rule, the source 

subcategory-specific emission 

performance rates are achievable in 

accordance with those criteria in the 

case law. 

As noted, the building blocks include 

several features that assure that affected 

EGUs may implement them. The 

building blocks may be implemented 

through a range of methods, including 

through the purchase of ERCs and 

emission trading. In addition, the 

building blocks incorporate 

‘‘headroom.’’ Moreover, the source 

subcategory-specific emission 

performance rates apply on an annual or 

longer basis, so that short-term issues 

need not jeopardize compliance. In 

addition, we quantify the emission 

performance rates based on the degree 

of emission limitation achievable by 

affected EGUs in the region where 

application of the combined building 

blocks results in the least stringent 

emission rate. Because the means to 

implement the building blocks are 

widely available and because of the justnoted flexibilities and approaches to the 

emission performance rates, all types of 

affected steam generating units, 

operating throughout the lower-48 states 

and under all types of regulatory 

regimes, are able to implement building 

blocks 1, 2 and 3 and thereby achieve 

the emission performance rate for fossil 

steam units, and all types of NGCC units 

operating in all states under all types of 

regulatory requirements are able to 

implement building block 3 and thereby 

achieve the emission performance rate 

for NGCC units.437

Commenters have raised questions 

about whether particular circumstances 

could arise, such as the sudden loss of 

certain generation assets, that would 

cause the implementation of the 

building blocks to cause reliability 

problems, and have cautioned that these 

circumstances could preclude 

implementation of the building blocks 

and thus achievement of the emission 

performance rates. Commenters have 

also raised concerns about whether 

affected EGUs with limited remaining 

useful lives can implement the building 

blocks and achieve the emission 

performance rates. We address those 

concerns in section VIII, where we 

authorize state plans to include a 

reliability mechanism and discuss 

affected EGUs with limited remaining 

useful lives. Accordingly, we conclude 

that the source subcategory-specific 

emission performance standards are 

achievable in accordance with the case 

law. 

5. Actions Under the BSER That Sources 

Can Take To Achieve Standards of 

Performance 

Based on the determination of the 

BSER described above, the EPA has 

identified a performance rate of 1305 

lbs. per net MWh for affected steam 

EGUs and a performance rate of 771 lbs. 

per net MWh for affected stationary 

combustion turbines. The computations 

of these performance rates and the 

determinations of state goals reflecting 

these rates are described in sections VI 

and VII of the preamble, respectively. 

Under section 111(d), states 

determine the standards of performance 

for individual sources. The EPA is 

authorizing states to express the 

standards of performance applicable to 

affected EGUs as either emission ratebased limits or mass-based limits. As 

described above, the sets of actions that 

sources can take to comply with these 

standards implement or apply the BSER 

and, in that sense, may be understood 

as part of the BSER. 

A source to which a state applies an 

emission rate-based limit can achieve 

the limit through a combination of the 

following set of measures (to the extent 

allowed by the state plan), all of which 

are components of the BSER, again, in 

the sense that they implement or apply 

it: 

• Reducing its heat rate (building block 1). 

• Directly investing in, or purchasing ERCs 

created as a result of, incremental generation 

from existing NGCC units (building block 2). 

• Directly investing in, or purchasing ERCs 

created as a result of, generation from new or 

uprated RE generators (building block 3). 

• Reducing its utilization, coupled with 

direct investment in or purchase of ERCs 

representing building blocks 2 and 3 as 

indicated above. 

• Investing in surplus emission rate 

reductions at other affected EGUs through the 

purchase or other acquisition of rate-based 

emission credits. 

A source to which a state applies a 

mass-based limit can achieve the limit 

through a combination of the following 

set of measures (to the extent allowed by 

the state plan), all of which are likewise 

components of the BSER: 

• Reducing its heat rate (building block 1). 

• Reducing its utilization and allowing its 

generation to be replaced or avoided through 

the routine operation of industry reliability 

planning mechanisms and market incentives. 

• Investing in surplus emission reductions 

at other affected EGUs through the purchase 

or other acquisition of mass-based emission 

allowances. 

The EPA has determined appropriate 

CO2 emission performance rates for each 

of the two source subcategories as a 

whole achievable through application of 

the building blocks. The wide ranges of 

measures included in the BSER and 

available to individual sources as 

indicated above provide assurance that 

the source category as a whole can 

achieve standards of performance 

consistent with those emissions 

standards using components of the 

BSER, whether states choose to establish 

emission rate-based limits or massbased limits. The wide ranges of 

measures included in the BSER also 

provide assurance that each individual 

affected EGU could achieve the standard 

of performance its state establishes for it 

using components of the BSER. Of 

course, sources may also employ 

measures not included in the BSER, to 

the extent allowed under the applicable 

state plan. 

In the remainder of this subsection, 

we discuss further how affected EGUs 

can use each of the measures listed 

above to achieve emission rate-based 

forms of performance standards and 

mass-based forms of performance 

standards, indicating that all types of 

owner/operators of affected EGUs—i.e., 

vertically integrated utilities and 

merchant generators; investor-owned, 

government-owned, and customerowned (cooperative) utilities; and 

owner/operators of large, small, and 

single-unit fleets of generating units— 

have the ability to implement each of 

the building blocks in some way. In the 

following subsection we discuss the use 


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438Each of these methods of implementing 

building block 2 meets the criteria for the BSER in 

that (i) as we discuss in section V.D. and supporting 

documents, each of these methods is adequately 

demonstrated;(ii) the costs of each of these methods 

on a source-by-source basis are reasonable, as 

discussed above; and (iii) none of these methods 

causes adverse energy impacts or non-quality 

environmental impacts. 

439As with building block 2, each of these 

methods of implementing building block 3 meets 

the criteria for the BSER in that (i) as we discuss 

in section V.E. and supporting documents, each of 

these methods is adequately demonstrated; (ii) the 

costs of each of these methods on a source-bysource basis are reasonable, as discussed above; and 

(iii) none of these methods causes adverse energy 

impacts or non-quality environmental impacts. 

440The possible use of types of RE generating 

capacity that are not included in the BSER is 

discussed in section V.A.6. and section VIII of the 

preamble. 

of measures not in the BSER that can 

help sources achieve the standards of 

performance. 

a. Use of BSER measures to achieve 

an emission rate-based standard. Under 

an emission-rate based form of 

performance standards, compliance is 

nominally determined through a 

comparison of the affected EGU’s 

emission rate to the emission rate 

standard. The emissions-reducing 

impact of BSER measures that reduce 

CO2 emissions through reductions in the 

quantity of generation rather than 

through reductions in the amount of 

CO2 emitted per unit of generation 

would not be reflected in an affected 

EGU’s emission rate computed solely 

based on measured stack emissions and 

measured electricity generation but can 

readily be reflected in an emission rate 

computation by averaging ERCs 

acquired by the affected EGU into the 

rate computation. 

In section VIII.K, we discuss the 

processes for issuance and use of ERCs 

that can be included in the emission 

rate computations that affected EGUs 

perform to demonstrate compliance 

with an emission rate standard. This 

ERC mechanism is analogous to the 

approach the EPA has used to reflect 

building blocks 2 and 3 in the uniform 

emission rates representing the BSER, as 

discussed in section VI below. As 

summarized below and as discussed in 

greater detail in section VIII.K, the 

existence of a clearly feasible path for 

usage of ERCs ensures that emission 

reductions achievable through 

implementation of the measures in 

building blocks 2 and 3 are available to 

assist all affected EGUs in achieving 

compliance with standards of 

performance based on the BSER. 

(1) Building block 1. 

The owner/operator of an affected 

steam EGU can take steps to reduce the 

unit’s heat rate, thereby lowering the 

unit’s CO2 emission rate. Examples of 

actions in this category are included in 

section V.C. below and in the GHG 

Mitigation Measures TSD for the CPP 

Final Rule. Any type of owner/operator 

can take advantage of this measure. 

(2) Building block 2. 

The owner/operator of an affected 

EGU can average the EGU’s emission 

rate with ERCs issued on the basis of 

incremental generation from an existing 

NGCC unit. As permitted under the 

EGU’s state’s section 111(d) plan, the 

owner/operator of the affected EGU 

could accomplish this through either 

common ownership of the NGCC unit, 

a bilateral transaction with the owner/ 

operator of the NGCC unit, or a 

transaction for ERCs through an 

intermediary, which could but need not 

involve an organized market.438 As 

discussed earlier, based on observation 

of market behavior both inside and 

outside the electricity industry, we 

expect that intermediaries will seek 

opportunities to participate in such 

transactions and that organized markets 

are likely to develop as well if section 

111(d) plans authorize the use of ERCs. 

While the opportunity to acquire ERCs 

through common ownership of NGCC 

facilities might not extend to owner/

operators of single EGUs or small fleets, 

all owner/operators would have the 

ability to engage in bilateral or 

intermediated purchase transactions for 

ERCs just as they can engage in 

transactions for other kinds of goods 

and services. 

In section VIII.K below, the EPA sets 

out the minimum criteria that must be 

satisfied for generation and issuance of 

a valid ERC based upon incremental 

electricity generation by an existing 

NGCC unit. Those criteria generally 

concern ensuring that the physical basis 

for the ERC—i.e., qualifying generation 

by an existing NGCC unit and the NGCC 

unit CO2 emissions associated with that 

qualifying generation—is adequately 

monitored and that there is an adequate 

administrative process for tracking 

credits to avoid double-counting. In the 

case of ERCs related to building block 2, 

the monitoring criteria would generally 

be satisfied by standard 40 CFR part 75 

monitoring. 

The owner/operator of an affected 

steam EGU would use the ERCs it has 

acquired for compliance—whether 

acquired through ownership of NGCC 

capacity, a bilateral transaction, or an 

intermediated transaction—by adding 

the ERCs to its measured net generation 

when computing its CO2 emission rate 

for purposes of demonstrating 

compliance with its emission rate-based 

standard of performance. 

(3) Building block 3. 

The owner/operator of an affected 

EGU can average the EGU’s emission 

rate with ERCs issued on the basis of 

generation from new (i.e., post-2012) RE 

generating capacity, including both 

newly constructed capacity and new 

uprates to existing RE generating 

capacity. As permitted under the EGU’s 

state’s section 111(d) plan, the owner/

operator of the affected EGU could 

accomplish this through either common 

ownership of the RE generating 

capacity, a bilateral transaction with the 

owner/operator of the RE generating 

capacity, or a transaction for ERCs 

through an intermediary, which could, 

but need not, involve an organized 

market.439 As discussed earlier, based 

on observation of market behavior both 

inside and outside the electricity 

industry, we expect that intermediaries 

will seek opportunities to participate in 

such transactions and that organized 

markets are likely to develop as well if 

section 111(d) plans authorize the use of 

ERCs. While the opportunity to acquire 

ERCs through common ownership of RE 

generating facilities might not extend to 

owner/operators of single EGUs or small 

fleets, all owner/operators would have 

the ability to engage in bilateral or 

intermediated purchase transactions for 

ERCs just as they can engage in 

transactions for other kinds of goods 

and services. 

In section VIII.K below, the EPA sets 

out the minimum criteria that must be 

satisfied for generation and issuance of 

a valid ERC based upon generation from 

new RE generating capacity. Those 

criteria generally concern assuring that 

the physical basis for the ERC—i.e., 

generation by qualifying new RE 

capacity—is adequately monitored and 

that there is an adequate administrative 

process for tracking credits to avoid 

double-counting.440

As with building block 2, the owner/ 

operator of an affected EGU would use 

the ERCs it has acquired for 

compliance—whether acquired through 

ownership of qualifying RE generating 

capacity, a bilateral transaction, or an 

intermediated transaction—by adding 

the ERCs to its measured net generation 

when computing its CO2 emission rate 

for purposes of demonstrating 

compliance with its emission rate-based 

standard of performance. 

(4) Reduced generation. 

The owner/operator of an affected 

EGU can reduce the unit’s generation 

and reflect that reduction in the form of 

a lower emission rate provided that the 

owner/operator also acquires some 

amount of ERCs to use in computing the 

unit’s emission rate for purposes of 

demonstrating compliance. As 


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permitted under the EGU’s state’s 

section 111(d) plan, the ERCs could be 

acquired through investment in 

incremental generation from existing 

NGCC capacity, generation from new RE 

generating capacity, or purchase from an 

entity with surplus ERCs. If the owner/ 

operator does not average any ERCs into 

the unit’s emission rate, reducing the 

unit’s own generation will 

proportionately reduce both the 

numerator and denominator of the 

fraction and therefore will not affect the 

computed emission rate (unless the unit 

retires, reducing its emission rate to 

zero). However, if the owner/operator 

does average ERCs into the unit’s 

emission rate, then a proportional 

reduction in both the numerator and the 

portion of the denominator representing 

the unit’s measured generation will 

amplify the effect of the acquired ERCs 

in the computation, with the result that 

the more the unit reduces its generation, 

the fewer ERCs will be needed to reach 

a given emission rate-based standard of 

performance. All owner/operators have 

the ability to reduce generation, and as 

discussed above all also would be 

capable of acquiring ERCs, so all would 

be capable of reflecting reduced 

utilization in their emission rates for 

purposes of demonstrating compliance. 

(5) Emissions trading approaches. 

To the extent allowed under 

standards of performance that 

incorporate emissions trading or 

otherwise through the relevant section 

111(d) plans, the owner/operator of an 

affected EGU can acquire tradable ratebased emission credits representing an 

investment in surplus emission rate 

reductions not needed by another 

affected EGU and can average those 

credits into its own emission rate for 

purposes of demonstrating compliance 

with its rate-based standard of 

performance. The approach would have 

to be authorized in the appropriate 

section 111(d) plan and would have to 

conform to the minimum conditions for 

such approaches described in section 

VIII below. As we have repeatedly 

noted, based on our reading of the 

comment record and the discussions 

that occurred during the outreach 

process, it is reasonable to presume that 

such authorization will be forthcoming 

from states that submit plans 

establishing rate-based standards of 

performance for their affected EGUs. 

Under a rate-based emissions trading 

approach, credits are initially created 

and issued according to processes 

defined in the state plan. After credits 

are initially issued, the owner/operator 

of an affected EGU needing additional 

credits can acquire credits through 

common ownership of another affected 

EGU or through a bilateral transaction 

with the other affected EGU, or the 

owner/operator of the affected EGU can 

acquire credits in a transaction through 

an intermediary, which could, but need 

not, involve an organized market. As 

discussed earlier, based on observation 

of market behavior both inside and 

outside the electricity industry, we 

expect that intermediaries will seek 

opportunities to participate in such 

transactions and that organized markets 

are likely to develop as well if section 

111(d) plans and/or standards of 

performance established thereunder 

authorize emissions trading. While the 

opportunity to acquire credits through 

common ownership might not extend to 

owner/operators of single EGUs or small 

fleets, all owner/operators would have 

the ability to engage in bilateral or 

intermediated purchase transactions for 

credits just as they can engage in 

transactions for other kinds of goods 

and services. 

Further details regarding the possible 

use of rate-based emission credits in a 

state plan (using ERCs issued on the 

basis of investments in building blocks 

2 and 3 and potentially other measures 

as the credits) are provided in section 

VIII.K. 

b. Use of BSER measures to achieve a 

mass-based standard. Under a massbased form of the standard, compliance 

is determined through a comparison of 

the affected EGU’s monitored mass 

emissions to a mass-based emission 

limit. Although a state could choose to 

impose specific mass-based limits that 

each EGU would be required to meet on 

a physical basis, in past instances where 

mass-based limits have been established 

for large numbers of sources it has been 

typical for the limit on each affected 

EGU to be structured as a requirement 

to periodically surrender a quantity of 

emission allowances equal to the 

source’s monitored mass emissions. The 

EPA believes that section 111(d) 

encompasses the flexibility for plans to 

impose mass-based standards in the 

typical manner where the standard of 

performance for each affected EGU 

consists of a requirement to surrender 

emission allowances rather than a 

requirement to physically comply with 

a unit-specific emissions cap. 

Measurements of mass emissions at a 

given affected EGU capture reductions 

in the EGU’s emissions arising from 

both reductions in generation and 

reductions in the emission rate per 

MWh. Accordingly, under a mass-based 

standard there is no need to provide a 

mechanism such as the ERC mechanism 

described above in order to properly 

account for emission reductions 

attributable to particular types of BSER 

measures. The relative simplicity of the 

mechanics of monitoring and 

determining compliance are significant 

advantages inherent in the use of massbased standards rather than emission 

rate-based standards. 

(1) Building block 1. 

The owner/operator of an affected 

steam EGU can take steps to reduce the 

unit’s heat rate, thereby lowering the 

unit’s CO2 mass emissions. Examples of 

actions in this category are included in 

section V.C. below and in the GHG 

Mitigation Measures TSD for the CPP 

Final Rule. Any type of owner/operator 

can take advantage of this measure. 

(2) Reduced generation. 

The owner/operator of an affected 

EGU can reduce its generation, thereby 

lowering the unit’s CO2 mass emissions. 

Any type of owner/operator can take 

advantage of this measure. Although 

some action or combination of actions to 

increase lower-carbon generation or 

reduce electricity demand somewhere 

in the interconnected electricity system 

of which the affected EGU is a part will 

be required to enable electricity supply 

and demand to remain in balance, the 

affected EGU does not need to monitor 

or track those actions in order to use its 

reduction in generation to help achieve 

compliance with the mass-based 

standard. Instead, multiple participants 

in the interconnected electricity system 

will act to ensure that supply and 

demand remain in balance, subject to 

the complex and constantly changing 

set of constraints on operation of the 

system, just as those participants have 

routinely done for years. 

Of course, if the owner/operator of the 

affected EGU wishes to play a direct role 

in driving the increase in lower-carbon 

generation or demand-side EE required 

to offset a reduction in the affected 

EGU’s generation, the owner/operator 

may do so as part of whatever role it 

happens to play as a participant in the 

interconnected electricity system. 

However, the owner/operator will 

achieve the benefit that reduction in 

generation brings toward compliance 

with the mass-based standard whether it 

takes those additional actions itself or 

instead allows other participants in the 

interconnected electricity system to play 

that role. 

(3) Emissions trading approaches. 

To the extent allowed under the 

relevant section 111(d) plans—as the 

record indicates that it is reasonable to 

expect it will be—the owner/operator of 

an affected EGU can acquire tradable 

mass-based emission allowances 

representing investment in surplus 

emission reductions not needed by 

another affected EGU and can aggregate 

those allowances with any other 


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allowances it already holds for purposes 

of demonstrating compliance with its 

mass-based standard of performance. 

The approach would have to be 

authorized in the appropriate section 

111(d) plan and would have to conform 

to the minimum conditions for such 

approaches described in section VIII 

below. 

Under a mass-based emissions trading 

approach, the total number of 

allowances to be issued is defined in the 

state plan, and affected EGUs may 

obtain an initial quantity of allowances 

through an allocation or auction 

process. After that initial process, the 

owner/operator of an affected EGU 

needing additional allowances can 

acquire allowances through common 

ownership of another affected EGU or 

through a bilateral transaction with the 

other affected EGU, or the owner/

operator of the affected EGU can acquire 

allowances in a transaction through an 

intermediary, which could but need not 

involve an organized market. As 

discussed earlier, based on observation 

of market behavior both inside and 

outside the electricity industry, we 

expect that intermediaries will seek 

opportunities to participate in such 

transactions and that organized markets 

are likely to develop as well if section 

111(d) plans authorize the use of 

emissions trading. While the 

opportunity to acquire allowances 

through common ownership might not 

extend to owner/operators of single 

EGUs or small fleets, all owner/

operators would have the ability to 

engage in bilateral or intermediated 

purchase transactions for allowances 

just as they can engage in transactions 

for other kinds of goods and services. 

Further details regarding the possible 

use of mass-based emission allowances 

in a state plan are provided in section 

VIII.J. 

6. Use of Non-BSER Measures To 

Achieve Standards of Performance 

In addition to the BSER-related 

measures that affected EGUs can use to 

achieve the standards of performance 

set in section 111(d) plans, there are a 

variety of non-BSER measures that 

could also be employed (to the extent 

permitted under a given plan). This 

final rule does not limit the measures 

that affected EGUs may use for 

achieving standards of performance to 

measures that are included in the BSER; 

thus, the existence of these non-BSER 

measures provides flexibility allowing 

the individual affected EGUs and the 

source category to achieve emission 

reductions consistent with application 

of the BSER at the levels of stringency 

reflected in this final rule even if one or 

more of the building blocks is not 

implemented to the degree that the EPA 

has determined to be reasonable for 

purposes of quantifying the BSER. In 

this way, non-BSER measures provide 

additional flexibility to states in 

establishing standards of performance 

for affected EGUs through section 111(d) 

plans and to individual affected EGUs 

for achieving those standards. 

Any of the non-BSER measures 

described below would help the affected 

source category as a whole achieve 

emission limits consistent with the 

BSER. The non-BSER measures either 

reduce the amount of CO2 emitted per 

MWh of generation from the set of 

affected EGUs or reduce the amount of 

generation, and therefore associated CO2

emissions, from the set of affected 

EGUs. However, the manner in which 

the various non-BSER measures would 

help individual affected EGUs meet 

their individual standards of 

performance varies according to the 

type of measure and the type of 

standard of performance—i.e., whether 

the standard is emission rate-based or 

mass-based. 

In general, a non-BSER measure that 

reduces the amount of CO2 emitted per 

MWh of generation at an affected EGU 

will reduce the amount of CO2

emissions monitored at the EGU’s stack 

(assuming the quantity of generation is 

held constant). Measures of this type 

can help the EGU meet either an 

emission rate-based or mass-based 

standard of performance. 

Other non-BSER measures do not 

reduce an affected EGU’s CO2 emission 

rate but rather facilitate reductions in 

CO2 emissions by reducing the amount 

of generation from affected EGUs. Under 

a mass-based standard, the collective 

reduction in emissions from the set of 

affected EGUs is reflected in the 

collective monitored emissions from the 

set of affected EGUs. An individual EGU 

that reduces its generation and 

emissions will be able to use the 

measure to help achieve its mass-based 

limit. Individual EGUs that do not 

reduce their generation and emissions 

will be able to use the measure, if the 

relevant section 111(d) plans provide for 

allowance trading, by purchasing 

emission allowances no longer needed 

by EGUs that have reduced their 

emissions. 

Under an emission rate-based 

standard, non-BSER measures that 

reduce generation from affected EGUs 

but do not reduce an affected EGU’s 

emission rate generally can facilitate 

compliance by serving as the basis for 

ERCs that affected EGUs can average 

into their emission rates for purposes of 

demonstrating compliance. Section 

VIII.K. includes a discussion of the 

issuance of ERCs based on various nonBSER measures. Affected EGUs could 

use such ERCs to the extent permitted 

by the relevant section 111(d) plans. 

The remainder of this section 

discusses some specific types of nonBSER 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, but 

merely a set of examples that illustrate 

the extent of the additional flexibility 

such measures provide to states and 

affected EGUs under the final rule. 

a. Non-BSER measures that reduce 

CO2 emissions per MWh generated. In 

the June 2014 proposal, the EPA 

discussed several potential measures 

that could reduce CO2 emissions per 

MWh generated at affected EGUs but 

that were not proposed to be part of the 

BSER. The measures discussed included 

heat rate improvements at affected EGUs 

other than coal-fired steam EGUs; fuel 

switching from coal to natural gas at 

affected EGUs, either completely 

(conversion) or partially (co-firing); and 

carbon capture and storage by affected 

EGUs. One reason for not proposing to 

consider these measures to be part of the 

BSER was that they were more costly 

than the BSER measures. Another 

reason was that the emission reduction 

potential was limited compared to the 

potential available from the measures 

that were proposed to be included in the 

BSER. However, we also noted that 

circumstances could exist where these 

measures could be sufficiently attractive 

to deploy, and that the measures could 

be used to help affected EGUs achieve 

emission limits consistent with the 

BSER. 

In the final rule, the EPA has reached 

determinations consistent with the 

proposal with respect to these measures: 

namely, that they do not merit inclusion 

in the BSER, but that they are capable 

of helping affected EGUs achieve 

compliance with standards of 

performance and are likely to be used 

for that purpose by some units. To the 

extent that they are selectively 

employed, they provide flexibility for 

the source category as a whole and for 

individual affected EGUs to achieve 

emission limits reflective of the BSER, 

as discussed above. 


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441However, 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. 

(1) Heat rate improvement at affected 

EGUs other than coal-fired steam EGUs. 

Building block 1 reflects the 

opportunity to improve heat rate at coalfired steam EGUs but not at other 

affected EGUs. As the EPA stated at 

proposal, the potential CO2 reductions 

available from heat rate improvements 

at coal-fired steam EGUs are much 

larger than the potential CO2 reductions 

available from heat rate improvements 

at other types of EGUs, and comments 

offered no persuasive basis for reaching 

a different conclusion. Nevertheless, we 

recognize that there may be instances 

where an owner/operator finds heat rate 

improvement to be an attractive option 

at a particular non-coal-fired affected 

EGU, and nothing in the rule prevents 

the owner/operator from implementing 

such a measure and using it to help 

achieve a standard of performance. 

(2) Carbon capture and storage at 

affected EGUs. 

Another approach for reducing CO2

emissions per MWh of generation from 

affected EGUs is the application of 

carbon capture and storage (CCS) 

technology. Consistent with the June 

2014 proposal, we are determining that 

use of full or partial CCS technology 

should not be part of the BSER for 

existing EGUs because it would be more 

expensive than the measures 

determined to be part of the BSER, 

particularly if applied broadly to the 

overall source category. At the same 

time, we note that retrofit of CCS 

technology may be a viable option at 

some individual facilities, particularly 

where the captured CO2 can be used for 

enhanced oil recovery (EOR). For 

example, construction of one CCS 

retrofit application with EOR has 

already been completed at a unit at the 

Boundary Dam plant in Canada, and 

construction of another CCS retrofit 

application with EOR is underway at 

the W.A. Parish plant in Texas. We 

expect the costs of CCS to decline as 

implementation experience increases. 

CO2 emission rate reductions achieved 

through retrofit of CCS technology 

would be available to help affected 

EGUs achieve emission limits consistent 

with the BSER. State plan 

considerations related to CCS are 

discussed in section VIII.I.2.a. 

(3) Fuel switching to natural gas at 

affected EGUs. 

In the proposal we discussed the 

opportunity to reduce CO2 emissions at 

an individual affected EGU by switching 

fuels at the EGU, particularly by 

switching from coal to natural gas. Most 

coal-fired EGUs could be modified to 

burn natural gas instead, and the 

potential CO2 emission reductions from 

this measure are large—approximately 

40 percent in the case of conversion 

from 100 percent coal to 100 percent 

natural gas, and proportionately smaller 

for partial co-firing of coal with natural 

gas. The primary reason for not 

considering this measure part of the 

BSER, both at proposal and in this final 

rule, is that it is more expensive than 

the BSER measures. In particular, 

combusting natural gas in a steam EGU 

is less efficient and generally more 

costly than combusting natural gas in an 

NGCC unit. For the category as a whole, 

CO2 emissions can be achieved far more 

cheaply by combusting additional 

natural gas in currently underutilized 

NGCC capacity and reducing generation 

from coal-fired steam EGUs (building 

block 2) than by combusting natural gas 

instead of coal in steam EGUs. 

Some owner/operators are already 

converting some affected EGUs from 

coal to natural gas, and it is apparent 

that the measure can be attractive 

compared to alternatives in certain 

circumstances, such as when a unit 

must meet tighter unit-specific limits on 

emissions of non-GHG pollutants, the 

options for meeting those emission 

limits are costly, and retirement of the 

unit would necessitate transmission 

upgrades that are costly or cannot be 

completed quickly. CO2 emission 

reductions achieved in these situations 

are available to help achieve emission 

limits consistent with the BSER. 

(4) Fuel switching to biomass at 

affected EGUs. 

Some affected EGUs may seek to cofire qualified biomass with fossil fuels. 

The EPA recognizes that the use of some 

biomass-derived fuels can play an 

important role in controlling increases 

of CO2 levels in the atmosphere. As with 

the other 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.I.2.c describes the process 

and considerations for states proposing 

to use different kinds of biomass in state 

plans. 

(5) Waste heat-to-energy conversion at 

affected EGUs. 

Certain affected EGUs in urban areas 

or located near industrial or commercial 

facilities with needs for thermal energy 

may be able add new equipment to 

capture some of the waste heat from 

their electricity generation processes 

and use it to create useful thermal 

output, thereby engaging in combined 

heat and power (CHP) production. 

While the set of affected EGUs in 

locations making this measure feasible 

may be limited, where feasible the 

potential CO2 emission rate 

improvements can be substantial: 

Depending on the process used, the 

efficiency with which fuel is converted 

to useful energy can be increased by 25 

percent or more. The final rule allows 

an owner/operator applying CHP 

technology to an affected EGU to 

account for the increased efficiency by 

counting the useful thermal output as 

additional MWh of generation, thereby 

lowering the unit’s computed emission 

rate and assisting with achievement of 

an emission rate-based standard of 

performance. (The EPA notes that 

unless the unit also reduced its fuel 

usage, the addition of the capability to 

capture waste heat and produce useful 

thermal output would not reduce the 

unit’s mass emissions and therefore 

would not directly help the unit achieve 

a mass-based standard of 

performance.441) 

b. Non-BSER measures that reduce 

CO2 emissions by reducing fossil fuelfired 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 

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 ratebased standards of performance, 

affected EGUs would need to acquire 

ERCs based on the non-BSER activities 

that could be averaged into their 

emission rate computations for purposes 

of determining compliance with their 

standards of performance. 

(1) Demand-side EE. 

One of the major approaches available 

for achieving CO2 emission reductions 

from the utility power sector is demandside EE. In the June 2014 proposal, the 

EPA identified demand-side EE as one 

of the four proposed building blocks for 

the BSER. We continue to believe that 

significant emission reductions can be 

achieved by the source category through 

use of such measures at reasonable 

costs. In fact, we believe that the 

potential emission reductions from 

demand-side EE rival those from 

building blocks 2 and 3 in magnitude, 

and that demand-side EE is likely to 


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442The 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). 

represent an important component of 

some state plans, particularly in 

instances where a state prefers to 

develop a plan reflecting the state 

measures approach discussed in section 

VIII below. We also expect that many 

sources would be interested in 

including demand-side EE in their 

compliance strategies to the extent 

permitted, and we received comment 

that it should be permitted. 

For the reasons discussed in section 

V.B.3.c.(8) below, the EPA has 

determined not to include demand-side 

EE in the BSER in this final rule. 

However, the final rule authorizes 

generation avoided through investments 

in demand-side EE to serve as the basis 

for issuance of ERCs when appropriate 

conditions are met. In section VIII.K 

below, the EPA sets out the minimum 

criteria that must be satisfied for 

generation and issuance of a valid ERC 

based upon implementation of new 

demand-side EE programs. Those 

criteria generally concern ensuring that 

the physical basis for the ERC—in this 

case, generation avoided through 

implementation of demand-side EE 

measures—is adequately evaluated, 

measured, and verified and that there is 

an adequate administrative process for 

tracking credits. 

Through their authority over legal 

requirements such as building codes, 

states have the ability to drive certain 

types of demand-side EE measures that 

are beyond the reach of private-sector 

entities. The EPA recognizes that, by 

definition, this type of measure is 

beyond the ability of affected EGUs to 

invest in either directly or through 

bilateral arrangements. However, the 

final rule also authorizes generation 

avoided through such state policies to 

serve as the basis for issuance of ERCs 

that in turn can be used by affected 

EGUs. The section 111(d) plan would 

need to include appropriate provisions 

for evaluating, measuring, and verifying 

the avoided MWh associated with the 

state policies, consistent with the 

criteria discussed in section VIII.K 

below. 

(2) New or uprated nuclear generating 

capacity. 

In the June 2014 proposal, the EPA 

included generation from the five 

nuclear units currently under 

construction as part of the proposed 

BSER. As discussed above in section 

V.A.3.c., upon consideration of 

comments, we have determined that 

generation from these units should not 

be part of the BSER. However, we 

continue to observe that the zeroemitting generation from these units 

would be expected to replace generation 

from affected EGUs and thereby reduce 

CO2 emissions, and the continued 

commitment of the owner/operators to 

completion of the units is essential in 

order to realize that result. Accordingly, 

a section 111(d) plan may rely on ERCs 

issued on the basis of generation from 

these units and other new nuclear units. 

For the same reason, a plan may rely on 

ERCs issued on the basis of generation 

from uprates to the capacity of existing 

nuclear units. Requirements for state 

plan provisions intended to serve this 

purpose are discussed in section VIII.K. 

(3) Zero-emitting RE generating 

technologies not reflected in the BSER. 

The range of available zero-emitting 

RE generating technologies is broader 

than the range of RE technologies 

determined to be suitable for use in 

quantification of building block 3 as an 

element of the BSER. Examples of 

additional zero-emitting RE 

technologies not included in the BSER 

that could be used to achieve emission 

limits consistent with the BSER include 

offshore wind, distributed solar, and 

fuel cells. These technologies were not 

included in the range of RE technologies 

quantified for the BSER because they are 

generally more expensive than the 

measures that were included and the 

other measures in the BSER. However, 

these technologies are equally capable 

of replacing generation from affected 

EGUs and thereby reducing CO2

emissions. Further, as with any 

technology, there are likely to be certain 

circumstances where the costs of these 

technologies are more attractive relative 

to alternatives, making the technologies 

likely to be deployed to some extent. 

Indeed, distributed solar is already 

being widely deployed in much of the 

U.S. and offshore wind, while still 

unusual in this country, has been 

extensively deployed in some other 

parts of the world. We expect 

innovation in RE generating 

technologies to continue, making such 

technologies even more attractive over 

time. A section 111(d) plan may rely on 

ERCs issued on the basis of generation 

from new and uprated installations of 

these technologies. The necessary state 

plan provisions are discussed in section 

VIII.K. 

(4) Non-zero-emitting RE generating 

technologies. 

Generation from new or expanded 

facilities that combust qualified biomass 

or biogenic portions of municipal solid 

waste (MSW) to produce electricity can 

also replace generation from affected 

EGUs and thereby control CO2 levels in 

the atmosphere.442 While the EPA 

believes it is reasonable to consider 

generation from these fuels and 

technologies to be forms of RE 

generation, the fact that they can 

produce stack emissions containing CO2

means that a section 111(d) plan seeking 

to permit use of such generation to serve 

as the basis for issuance of ERCs must 

include appropriate consideration of 

feedstock characteristics and climate 

benefits. Specifically, the use of some 

kinds of biomass has the potential to 

offer a wide range of environmental 

benefits, including carbon benefits. 

However these benefits can only be 

realized if biomass feedstocks are 

sourced responsibly and attributes of 

the carbon cycle related to the biomass 

feedstock are taken into account. 

Section VIII.I.2.c describes the process 

and considerations for states proposing 

to use biomass in state plans. Section 

VIII.K describes additional provisions 

related to ERCs. 

(5) Waste heat-to-electricity 

conversion at non-affected facilities. 

Industrial facilities that install new 

equipment to capture waste heat from 

an existing combustion process and 

then use the waste heat to generate 

electricity—a form of combined heat 

and power (CHP) production—can 

produce generation that replaces 

generation from affected EGUs and 

thereby reduces CO2 emissions. A 

section 111(d) plan may rely on ERCs 

issued on the basis of generation of this 

nature provided that the facility does 

not generate and sell sufficient 

electricity to qualify as a new EGU for 

purposes of section 111(b) and is not 

covered under section 111(d) for 

another source category. More 

information is provided in section 

VIII.K. 

(6) Reduction in transmission and 

distribution line losses. 

Reductions of electricity line losses 

incurred from the transmission and 

distribution system between the points 

of generation and the points of 

consumption by end-users allow the 

same overall demand for electricity 

services to be met with a smaller overall 

quantity of electricity generation. Such 

reductions in generation quantities 

would tend to reduce generation by 

affected EGUs, thereby reducing CO2

emissions. The opportunity for 

improvement is large because, on 

average, line losses account for 

approximately seven percent of all 

electricity generation. The EPA 

recognizes that, in general, only the 


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443The heat rate improvement measures included 

in building block 1 are capable of being 

implemented independently of the measures in the 

other building blocks but, as discussed earlier, 

unless at least one other building block is also 

implemented, a ‘‘rebound effect’’ arising from 

improved competitiveness and increased generation 

at the EGUs implementing heat rate improvements 

could weaken or potentially even eliminate the 

ability of building block 1 to achieve CO2 emission 

reductions. 444This conclusion would not extend to a BSER 

comprising solely building block 1, in part because 

of the possibility of rebound effects discussed 

earlier. 

445Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 

2444 (2014). 

446See 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. 

447See ‘‘State Plans for the Control of Certain 

Pollutants From Existing Facilities,’’ 40 FR 53340 

(Nov. 17, 1975). 

448See ‘‘State Plans for the Control of Certain 

Pollutants From Existing Facilities,’’ 40 FR 53340 

(Nov. 17, 1975). 

449As we made clear in the proposed rulemaking, 

we are not re-opening these regulations (on the 

owner/operators of the transmission and 

distribution facilities have the ability to 

undertake line loss reduction 

investments, and that merchant 

generators may have little opportunity 

to engage a contractor to pursue such 

opportunities on a bilateral basis. 

Nevertheless, for entities that do have 

the opportunity to make such 

investments, generation avoided 

through investment that reduces 

transmission and distribution line losses 

may serve as the basis for issuance of 

ERCs that in turn can be used by 

affected EGUs. Further information is 

provided in section VIII.K. 

7. Severability 

The EPA intends that the components 

of the BSER summarized above be 

severable. It is reasonable to consider 

the building blocks severable because 

the building blocks do not depend on 

one another. Building blocks 2 and 3 are 

feasible and demonstrated means of 

reducing CO2 emissions from the utility 

power sector that can be implemented 

independently of the other building 

blocks. If implemented in combination 

with at least one of the other building 

blocks, building block 1 is also a 

feasible and demonstrated means of 

reducing CO2 emission from the utility 

power sector.443 As discussed in 

sections V.C. through V.E. below, we 

have determined that each building 

block is independently of reasonable 

cost whether or not the other building 

blocks are applied, and that alternative 

combinations of the building blocks are 

likewise of reasonable cost, and we have 

determined reasonable schedules and 

stringencies for implementation of each 

building block independently, based on 

factors that generally do not vary 

depending on the implementation of 

other building blocks. 

Further, building block 2, building 

block 3, and all combinations of the 

building blocks (implemented on the 

schedules and at the stringencies 

determined to be reasonable in this rule) 

would achieve meaningful degrees of 

emission reductions,444 although less 

than the combination of all three 

building blocks. No combination of the 

building blocks would lead to adverse 

non-air environmental or energy 

impacts or impose a risk to the 

reliability of electricity supplies. 

In the event that a court should deem 

building block 2 or 3 defective, but not 

both, the standards and state goals can 

be recomputed on the basis of the 

remaining building blocks. All of the 

data and procedures necessary to 

determine recomputed state goals using 

any combination of the building blocks 

are set forth in the CO2 Emission 

Performance Rate and Goal 

Computation TSD for the CPP Final 

Rule available in the docket. 

B. Legal Discussion of Certain Aspects 

of the BSER 

This section includes a legal analysis 

of various aspects of EPA’s 

determination of the BSER, including 

responses to some of the major adverse 

comments. These aspects include (1) the 

EPA’s authority to determine the BSER; 

(2) the approach to subcategorization; 

(3) the EPA’s basis for determining that 

building blocks 2 and 3 qualify as part 

of the BSER under CAA sections 

111(d)(1) and (a)(1), notwithstanding 

commenters’ arguments that these 

building blocks cannot be considered 

part of the BSER because they are not 

based on measures integrated into the 

design or operation of the affected 

source’s own production processes or 

methods or because they are dependent 

on actions by entities other than the 

affected source; (4) the relationship 

between an affected EGU’s 

implementation of building blocks 2 

and 3 and CO2 emissions reductions; (5) 

how reduced generation relates to the 

BSER; (6) reasons why, contrary to 

assertions by commenters, this rule is 

within the EPA’s statutory authority, is 

not inconsistent with the Federal Power 

Act or state laws governing public 

utility commissions, and does not result 

in what the U.S. Supreme Court 

described as ‘‘an enormous and 

transformative expansion in [the] EPA’s 

regulatory authority’’; 445 and (7) reasons 

that, contrary to assertions by 

commenters, the stringency of the BSER 

for this rule for CO2 emissions from 

existing affected EGUs is not 

inconsistent with the stringency of the 

BSER for the rules the EPA is 

promulgating at the same time for CO2

emissions from new or modified 

affected EGUs. 

1. The EPA’s Authority To Determine 

the BSER 

In this section, we explain why the 

EPA, and not the states, has the 

authority to determine the BSER and, 

therefore, the level of emission 

limitation required from the existing 

sources in the source category in section 

111(d) rulemaking and the associated 

state plans. 

CAA section 111(d)(1) requires the 

EPA to establish a section 110-like 

procedure under which each state 

submits a plan that ‘‘establishes 

standards of performance for any 

existing source of air pollutant’’ and 

‘‘provides for the implementation and 

enforcement of such standards of 

performance.’’ As CAA section 111(d) 

was originally adopted in the 1970 CAA 

Amendments, however, state plans were 

required to establish ‘‘emission 

standards’’—an undefined term—rather 

than ‘‘standards of performance,’’ a term 

that was limited to CAA section 

111(b).446 The 1970 provision was in 

effect when the EPA issued the 1975 

implementing regulations for CAA 

section 111(d),447 which remain in 

effect to this day. 

These regulations establish a 

cooperative framework that is similar to 

that under CAA section 110. First, the 

EPA develops ‘‘emission guidelines’’ for 

source categories, which are defined as 

a final guideline document reflecting 

‘‘the degree of emission reduction 

achievable through the application of 

the best system of emission reduction 

. . . which the Administrator has 

determined has been adequately 

demonstrated.’’ Then, the states submit 

implementation plans to regulate any 

existing sources.448

The preamble to these regulations 

carefully considered the allocation of 

responsibilities as between the EPA and 

the states for purposes of CAA section 

111(d), and concluded that the EPA is 

responsible for determining the level of 

emission limitation from the source 

category, while the states have the 

responsibility of assigning emission 

requirements to their sources that 

assured their achievement of that level 

of emission limitation.449 The EPA 


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issue of the authority to determine the BSER or any 

other issue, unless specifically indicated otherwise) 

in this rulemaking, and our discussion of these 

regulations in responding to comments does not 

constitute a re-opening. 

450 ‘‘State Plans for the Control of Certain 

Pollutants from Existing Facilities,’’ 40 FR 53340, 

53342 (Nov. 17, 1975). 

451 ‘‘State Plans for the Control of Certain 

Pollutants from Existing Facilities,’’ 40 FR 53340, 

53343 (Nov. 17, 1975). 

452 ‘‘State Plans for the Control of Certain 

Pollutants from Existing Facilities,’’ 40 FR 53340, 

53343 (Nov. 17, 1975). 

453H.R. Rep. No. 95–294, at 195 (May 12, 1977) 

(emphasis added). 

454H.R. Rep. No. 95–294, at 195 (May 12, 1977) 

(emphasis added). 

455CAA section 129(a)(1)(A) (emphasis added). 

456See 40 CFR part 60, subpart Ca (large 

municipal waste combustors), 56 FR 5514 (Feb. 11, 

1991), 40 CFR 60.30a–.39a (subsequently 

withdrawn and superseded by Subpart Cb, see 60 

FR 65387 (Dec. 19, 1995)); Subpart Cb (large 

municipal waste combustors constructed on or 

before September 20, 1994), 60 FR 65387 (Dec. 19, 

1995), 40 CFR 60.30b–.39b (as amended in 1997, 

2001, and 2006); Subpart Cc (municipal solid waste 

landfills), 61 FR 9905 (Mar. 12, 1996), 40 CFR 

60.30c–.36c (as amended in 1998, 1999, and 2000); 

Subpart Cd (sulfuric acid production units), 60 FR 

65387 (Dec. 19, 1995), 40 CFR 60.30d–.32d; Subpart 

Ce (hospital/medical/infectious waste incinerators), 

62 FR 48348 (Sept. 15, 1997), 40 CFR 60.30e–.39e 

(as amended in 2009 and 2011); Subpart BBBB 

(small municipal waste combustion units 

constructed on or before August 30, 1999), 65 FR 

76738 (Dec. 6, 2000), 40 CFR 60.1500–.1940; 

Subpart DDDD (commercial and industrial solid 

waste incineration units that commenced 

construction on or before November 30, 1999), 65 

FR 75338 (Dec. 1, 2000), 40 CFR 60.2500–.2875 (as 

amended in 2005, 2011, and 2013); Subpart FFFF 

(other solid waste incineration units that 

commenced construction on or before December 9, 

2004), 70 FR 74870 (Dec. 16, 2005), 40 CFR 

60.2980–.3078 (as amended in 2006); Subpart 

HHHH (coal-electric utility steam generating units), 

70 FR 28606 (May 18, 2005) (subsequently vacated 

by the D.C. Circuit in New Jersey v. EPA, 517 F.3d 

574 (D.C. Cir. 2008)); Subpart MMMM (existing 

sewage sludge incineration units), 76 FR 15372 

(Mar. 21, 2011), 40 CFR 60.5000–.5250; ‘‘Phosphate 

Fertilizer Plants, Final Guideline Document 

Availability,’’ 42 FR 12022 (Mar. 1, 1977) (not 

codified); ‘‘Kraft Pulp Mills; Final Guideline 

Document; Availability,’’ 44 FR 29828 (May 22, 

1979) (not codified); and ‘‘Primary Aluminum 

Plants; Availability of Final Guideline Document,’’ 

45 FR 26294 (Apr. 17, 1980) (not codified). 

457Scalia, Antonin, Judicial Deference to 

Administrative Interpretations of Law, 1989 Duke 

L.J. 511, 518; see Riverkeeper v. Entergy, 556 U.S. 

208, 235 (2009). 

458Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 

2527, 2537–38 (2011). 

explained ‘‘that some substantive 

criterion was intended to govern not 

only the Administrator’s promulgation 

of standards but also [her] review of 

state plans.’’ 450 The EPA added, ‘‘it 

would make no sense to interpret [CAA] 

section 111(d) as requiring the 

Administrator to base approval or 

disapproval of state plans solely on 

procedural criteria. Under that 

interpretation, states could set 

extremely lenient standards—even 

standards permitting greatly increased 

emissions—so long as [the] EPA’s 

procedural requirements were met.’’ 451

The EPA concluded that ‘‘emission 

guidelines, each of which will be 

subjected to public comment before 

final adoption, will serve [the] function’’ 

of providing substantive criteria ‘‘in 

advance to the states, to industry, and 

to the general public’’ to aid states in 

‘‘developing and enforcing control plans 

under [CAA] section 111(d).’’ 452 Thus, 

the implementing regulations make 

clear that the EPA is responsible for 

determining the level of emission 

limitation that the state plans must 

achieve. 

In 1977, Congress revised CAA 

section 111(d) to require that the states 

adopt ‘‘standards of performance,’’ as 

defined under CAA section 111(a)(1). As 

noted above, a standard of performance 

is defined as ‘‘a standard for emissions 

of air pollutants which reflects the 

degree of emission limitation achievable 

through the application of the best 

system of emission reduction which 

. . . the Administrator determines has 

been adequately demonstrated.’’ 

(Emphasis added.) By its terms, this 

provision provides that the EPA has the 

responsibility of determining whether 

the ‘‘best system of emission reduction’’ 

is ‘‘adequately demonstrated.’’ By giving 

the EPA this responsibility, this 

provision is clear that Congress assigned 

the role of determining the ‘‘best system 

of emission reduction’’ to the EPA. Even 

if the provision may be considered to be 

silent or ambiguous on that question, 

the EPA reasonably interprets the 

provision to assign the responsibility of 

identifying the ‘‘best system of emission 

reduction’’ to the Administrator for the 

same reasons discussed in the preamble 

to the 1975 implementing regulations. 

In addition, in the legislative history 

of the 1977 CAA Amendments, when 

Congress replaced the term ‘‘emission 

standards’’ under CAA section 111(d)(1) 

with the term ‘‘standards of 

performance,’’ Congress endorsed the 

overall approach of the implementing 

regulations, which lends further 

credence to the proposition that the EPA 

has the responsibility for determining 

the ‘‘best system of emission reduction’’ 

and the amount of emission limitation 

from the existing sources. Specifically, 

in the House report that introduced the 

substantive changes to CAA section 111, 

the Committee explained that ‘‘[t]he 

Administrator would establish 

guidelines as to what the best system for 

each category of existing sources is.’’ 453

States, on the other hand, ‘‘would be 

responsible for determining the 

applicability of such guidelines to any 

particular source or sources.’’ 454 The 

use of the term ‘‘guidelines,’’ which 

does not appear in CAA section 111(d), 

indicates Congress was aware of and 

approved of the approach taken in the 

EPA’s implementing regulations for 

establishing guidelines, which 

determine the BSER. At a minimum, if 

Congress disapproved of the EPA’s 

implementing regulations, we would 

not expect the House report to adopt the 

EPA’s terminology to clarify CAA 

section 111(d). 

In addition, Congress expressly 

referred to our ‘‘guidelines’’ in CAA 

section 129, added as part of the 1990 

CAA Amendments. Congress added 

CAA section 129 to address solid waste 

combustion and specifically directed 

the Administrator to establish 

‘‘guidelines (under section 111(d) and 

this section) and other requirements 

applicable to existing units.’’ 455 This 

reference also indicates that Congress 

was aware of and approved the EPA’s 

regulations under section 111(d). 

The EPA has followed the same 

approach described in the 

implementation regulations in all its 

rulemakings under section 111(d). Thus, 

in all cases, the EPA has identified the 

type of emission controls for the source 

category and the level of emission 

limitation based on those controls.456

The EPA’s longstanding and consistent 

interpretation of CAA section 111(d) is 

also ‘‘evidence showing that the statute 

is in fact not ambiguous,’’ and that the 

EPA’s interpretation should be 

adopted.457

Lastly, this interpretation is consistent 

with the Supreme Court’s reading of 

CAA section 111(d) in American 

Electric Power Co. There, the Court 

explained that ‘‘EPA issues emissions 

guidelines, see 40 CFR 60.22, .23 (2009); 

in compliance with those guidelines 

and subject to federal oversight, the 

States then issue performance standards 

for stationary sources within their 

jurisdiction, § 7411(d)(1).’’ 458

As noted in the response to comment 

document, some commenters agreed 

with our interpretation, just discussed, 

while others argued that the states 

should be given the authority to 

determine the best system of emission 

reduction and, therefore, the level of 

emission limitation from their sources. 

For the reasons just discussed, this latter 

interpretation is an incorrect 

interpretation of CAA section 111(d)(1) 

and (a)(1), and we are not compelled to 

abandon our longstanding practice. 

2. Approach to Subcategorization 

As noted above, in this rule, we are 

treating all fossil fuel-fired EGUs as a 

single category, and, in the emission 


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459CAA section 111(b)(1)(A). 

460CAA section 111(b)(1)(B). 

461CAA section 111(b)(2). 

462Compare ‘‘Revision of Standards of 

Performance for Nitrogen Oxide Emissions From 

New Fossil-Fuel Fired Steam Generating Units; 

Revisions to Reporting Requirements for Standards 

of Performance for New Fossil-Fuel Fired Steam 

Generating Units: Final Rule,’’ 63 FR 49442 (Sept. 

16, 1998) and ‘‘Proposed Revision of Standards of 

Performance for Nitrogen Oxide Emissions From 

New Fossil-Fuel Fired Steam Generating Units: 

Proposed Revisions,’’ 62 FR 36948, 36943 (July 9, 

1997) (establishing a single NOX emission limit for 

new fossil-fuel fired steam generating units, and not 

subcategorizing, because the affected units could 

implement the BSER of SCR and achieve the 

promulgated emission limits) with ‘‘National 

Emission Standards for Hazardous Air Pollutants 

From Coal and Oil-Fired Electric Utility Steam 

Generating Units and Standards of Performance for 

Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units: 

Final Rule,’’ 77 FR 9304 (Feb. 16, 2012) (MATS 

rule) and ‘‘National Emission Standards for 

Hazardous Air Pollutants From Coal and Oil-Fired 

Electric Utility Steam Generating Units and 

Standards of performance for Fossil-Fuel-Fired 

Electric Utility, Industrial-Commercial-Institutional, 

and Small Industrial-Commercial-Institutional 

Steam Generating Units: Proposed Rule,’’ 76 FR 

24976, 25036–37 (May 3, 2011) (subcategorizing 

coal fired units designed to burn coal with greater 

than or equal to 8,300 Btu/lb (for Hg emissions 

only), coal-fired units designed to burn coal with 

less than 8,300 Btu/lb (for Hg emissions only), IGCC 

units, liquid oil units, and solid oil-derived units; 

evaluating ‘‘subcategorization of lignite coal vs. 

other coal ranks; subcategorization of Fort Union 

lignite coal vs. Gulf Coast lignite coal vs. other coal 

ranks; subcategorization by EGU size (i.e., MWe); 

subcategorization of base load vs. peaking units 

(e.g., low capacity utilization units); 

subcategorization of wall-fired vs. tangentially-fired 

units; and subcategorization of small, non-profitowned units vs. other units;’’ but deciding not to 

adopt those latter subcategorizations). 

463See, 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.’’). 

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 welfare 459 and then to 

regulate new sources within each such 

source category,460 and which grant the 

EPA discretion whether to subcategorize 

new sources for purposes of 

determining the BSER.461

For this rule, our approach of 

subcategorizing between steam EGUs 

and combustion turbines is reasonable 

because building blocks 1 and 2 apply 

only to steam EGUs. No further 

subcategorization is appropriate because 

each affected EGU can achieve the 

performance rate by implementing the 

BSER. Specifically, as noted, each 

affected EGU may take a range of actions 

including investment in the building 

blocks, replacing or reducing 

generation, and emissions trading, as 

enabled or facilitated by the 

implementation programs the states 

adopt. Further, in the case of a ratebased state plan, several other 

compliance options not included in the 

BSER for this rule are also available to 

all affected sources, including 

investment in demand-side EE 

measures. Such compliance options 

help affected sources achieve 

compliance under a mass-based plan, 

even if indirectly. Our approach to 

subcategorization in this rule is 

consistent with our approach to 

subcategorization in previous section 

111 rules for this industry, in which we 

determined whether or not to 

subcategorize on the basis of the ability 

of affected EGUs with different 

characteristics (e.g., size or type of fuel 

used) to implement the BSER and 

achieve the emission limits).462

In addition, there are numerous 

possible criteria to use in 

subcategorizing, including, among 

others, subcategorizing on the basis of 

age; size; steam conditions (i.e., 

subcritical or supercritical); type of fuel, 

including type of coal (i.e., lignite, 

bituminous, and sub-bituminous), and 

coal refuse; and method of combustion 

(i.e., fluidized bed combustion, 

pulverized coal combustion, and 

gasification). In addition, there are 

different possible combinations of those 

categories. At least some of those 

criteria do not have logical cut-points. 

Furthermore, we have not been 

presented with, nor can we discern, a 

method of subcategorizing based on 

these or other criteria that is appropriate 

in light of the BSER for the affected 

EGUs and their ability to meet the 

emission limits. Moreover, our approach 

of not further subcategorizing as 

between different types of steam EGUs 

or combustion turbines reflects the 

reasonable policy that affected EGUs 

with higher emission rates should 

reduce their emissions by a greater 

percentage than affected EGUs with 

lower emission rates, and can do so by 

implementing the BSER we are 

identifying. 

In addition, a section 111(d) rule 

presents less of a need to subcategorize 

because the states retain great flexibility 

in assigning standards of performance to 

their affected EGUs. Thus, a state can, 

if it wishes, impose different emission 

reduction obligations on its sources, as 

long as the overall level of emission 

limitation is at least as stringent as the 

emission guidelines, as discussed 

below. This means that if a state is 

concerned that its different sources have 

different capabilities for compliance, it 

can adjust the standards of performance 

in imposes on its sources accordingly. 

3. Building Blocks 2 and 3 as a ‘‘System 

of Emission Reduction’’ 

a. Overview. 

As we explain above, the emission 

performance rates that we include in 

this rule’s emission guidelines are 

achievable by the affected EGUs through 

the application of the BSER, which 

includes the three building blocks. 

Commenters object that building blocks 

2 (generation shift) and 3 (RE) cannot, 

as a legal matter, be considered part of 

the BSER under CAA section 111(d)(1) 

and (a)(1). These commenters explain 

that in their view, under CAA section 

111, the emission performance rates 

must be based on, and therefore the 

BSER must be limited to, methods for 

emission control that the owner/

operator of the affected source can 

integrate into the design or operation of 

the source itself, and cannot be based on 

actions taken beyond the source or 

actions involving third-party entities.463

For these reasons, these commenters 

argue that the phrase ‘‘system of 

emission reduction’’ cannot be 


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464Because 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 ‘‘catchall’’ 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. 

465This rule was vacated by the D.C. Circuit on 

other grounds. New Jersey v. EPA, 517 F.3d 574, 

583–84 (D.C. Cir. 2008), cert. denied sub nom. Util. 

Air Reg. Group v. New Jersey, 555 U.S. 1169 (2009). 

466As noted in the Legal Memorandum, in several 

of these rulemakings and in the course of litigation, 

the fossil fuel-fired electric power sector has taken 

positions that are consistent with the EPA’s 

interpretation that the BSER may include building 

blocks 2 and 3. 467CAA section 101(a)(2). 

interpreted to include building blocks 2 

and 3. 

We disagree with these comments, 

and note that other commenters were 

supportive of our determination to 

include building blocks 2 and 3. Under 

CAA section 111(d)(1) and (a)(1), the 

EPA’s emission guidelines must 

establish achievable emission limits 

based on the ‘‘best system of emission 

reduction . . . adequately 

demonstrated.’’ While some 

commenters assert that emission 

guidelines must be limited in the 

manner summarized above, the phrase 

‘‘system of emission reduction,’’ by its 

terms and when read in context, 

contains no such limits. To the contrary, 

its plain meaning is deliberately broad 

and is capacious enough to include 

actions taken by the owner/operator of 

a stationary source designed to reduce 

emissions from that 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, which includes the measures in 

building blocks 2 and 3. Furthermore, 

the measures in building blocks 2 and 

3 fall squarely within EPA’s historical 

interpretation of section 111, pursuant 

to which the focus for the BSER has 

been on how to most cleanly produce a 

good, not on how much of the good 

should be produced. 

Our interpretation that a ‘‘system of 

emission reduction’’ is broad enough to 

include the measures in building blocks 

2 and 3 is supported by the following: 

Our interpretation of the phrase ‘‘system 

of emission reduction’’ is consistent 

with its plain meaning and statutory 

context; our interpretation 

accommodates the very design of CAA 

section 111(d)(1), which covers a range 

of source categories and air 

pollutants; 464 our interpretation is 

supported by the legislative history of 

CAA section 111(d)(1) and (a)(1), which 

indicates Congress’s intent to give the 

EPA broad discretion in determining the 

basis for CAA section 111 control 

requirements, particularly for existing 

sources, and Congress’s intent to 

authorize the EPA to consider measures 

that could be carried out by parties 

other than the affected sources; and our 

interpretation is reasonable in light of 

comparisons to CAA provisions that 

give the EPA similar authority to 

consider such measures and to CAA 

provisions that would preclude the EPA 

from considering such measures. 

In addition to the reasons stated 

above, the EPA’s interpretation is also 

reasonable for the following reasons: (i) 

Building blocks 2 and 3 fit well within 

the structure and economics of the 

utility power sector. (ii) Fossil fuel-fired 

EGUs are already implementing the 

measures in these building blocks for 

various reasons, including for purposes 

of reducing CO2 emissions. (iii) 

Interpreting the phrase ‘‘system of 

emission reduction’’ to incorporate 

building blocks 2 and 3 is consistent 

with (a) other provisions in the CAA, 

including the acid rain provisions in 

Title IV and the SIP provisions in CAA 

section 110, along with the EPA’s 

regulations implementing the CAA SIP 

requirements concerning interstate 

transport and regional haze, each of 

which is based on at least some of the 

same measures included in building 

blocks 2 and 3; (b) prior EPA action 

under CAA section 111(d), including 

the 2005 Clean Air Mercury Rule,465

which is based on some of the same 

measures in building blocks 2 and 3; (c) 

the various provisions of the CAA that 

authorize emissions trading, because 

emissions trading entails a source 

meeting its emission limitation based on 

the actions of another entity; and (d) the 

pollution prevention provisions of the 

CAA, which make clear that a primary 

goal of the CAA is to encourage federal 

and state actions that reduce or 

eliminate, through any measures, the 

amount of pollution produced at the 

source.466 (iv) Lastly, interpreting the 

phrase ‘‘system of emission reduction’’ 

to authorize the EPA, in formulating its 

BSER determination, to weigh a broad 

range of emission-reducing measures 

that includes building blocks 2 and 3 is 

consistent with Congress’s intent to 

address urgent environmental problems 

and to protect public health and welfare 

against risks, as well as Congress’s 

expectation that American industry 

would be able to develop the innovative 

solutions necessary to protect public 

health and welfare. 

Congress passed the CAA, including 

its several amendments, to protect 

public health and welfare from 

‘‘mounting dangers,’’ including ‘‘injury 

to agricultural crops and livestock, 

damage to and the deterioration of 

property, and hazards to air and ground 

transportation.’’ 467 In doing so, 

Congress established numerous 

programs to address air pollution 

problems and provided the EPA with 

guidance and flexibility in carrying out 

many of those programs. Even if we 

were to accept commenters’ view that 

the system of emission reduction 

identified as best here is not integrated 

into the design or operation of the 

regulated sources, in the context of this 

industry and this pollutant it is 

reasonable to reject the narrow 

interpretation urged by some 

commenters that the ‘‘system of 

emission reduction’’ applicable to the 

affected EGUs must be limited to only 

those measures that can be integrated 

into the design or operation of the 

source itself. The plain language of the 

statute does not support such an 

interpretation, and to adopt it would 

limit the ‘‘system of emission 

reduction’’ to measures that are either 

substantially more expensive or 

substantially less effective at reducing 

emissions than the measures in building 

blocks 2 and 3, notwithstanding the 

absence of any statutory language 

imposing such a limit. Such a result 

would be contrary to the goals of the 

CAA and would ignore the facts that 

sources in the electric generation 

industry routinely address planning and 

operating objectives on a broad, multisource basis using the measures in 

building blocks 2 and 3 and would seek 

to use building blocks 2 and 3 (as well 

as non-BSER measures) to comply with 

whatever emission standards are set as 

a result of this rule. Indeed, as already 

observed, building blocks 2 and 3 are 

already being used to reduce emissions, 

and to do so specifically by operation of 

the industry’s inherent multi-source 

functions. 

Although the BSER provisions are 

sufficiently broad to include, for 

affected EGUs, the measures in building 

blocks 2 and 3, they also incorporate 

significant constraints on the types of 


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468As we note in section V.A., this rulemaking 

presents a unique set of circumstances, including 

the global nature of CO2 and the emission control 

challenges that CO2 presents (which limit the 

availability and effectiveness of control measures), 

combined with the facts that the electric power 

industry (including fossil fuel-fired steam 

generators and combustion turbines) is highly 

integrated, electricity is fungible, and generation is 

substitutable (which all facilitate the generation 

shifting measures encompassed in building blocks 

2 and 3). Our interpretation of section 111 as 

focusing on limiting emissions without limiting 

aggregate production must take into account those 

unique circumstances. 

469See 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.’’) 

470Oxford Dictionary of English (3rd ed.) (2010), 

available at http://www.oxforddictionaries.com/us/ 

definition/american_english/system; see also 

American Heritage Dictionary (5th ed.) (2013), 

available at http://www.yourdictionary.com/

system#americanheritage; and The American 

College Dictionary (C.L. Barnhart, ed. 1970) (‘‘an 

assemblage or combination of things or parts 

forming a complex or unitary whole’’). 

471While 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. 

472Some commenters read the proposed 

rulemaking as taking the position that the phrase 

‘‘system of emission reduction’’ includes anything 

whatsoever that reduces emissions, and criticized 

that interpretation as too broad. See UARG 

comment, at 3–4. We are not taking that 

interpretation here. In this final rule, we agree that 

the phrase should be limited to exclude, inter alia, 

actions beyond the ability of the owners/operators 

to control. 

measures that may be included in the 

BSER. We discuss those constraints at 

the end of this section. They include the 

section 111(d)(1) and (a)(1) 

requirements that emission reductions 

occur from the affected sources; that the 

emission performance standards for 

which the BSER forms the basis be 

achievable; that the system of emission 

reduction be adequately demonstrated; 

and that the EPA account for cost, nonair quality impacts, and energy 

requirements in determining the ‘‘best’’ 

system of emission reduction that is 

adequately demonstrated. The 

constraints included in these statutory 

requirements do not preclude building 

blocks 2 and 3 from the BSER. In 

interpreting these statutory 

requirements for determining the BSER, 

the EPA is consistent with past practice 

and current policy for both section 111 

regulatory actions as well as regulatory 

actions under other CAA provisions for 

the electric power sector, under which 

the EPA has generally taken the 

approach of basing regulatory 

requirements on controls and measures 

designed to reduce air pollutants from 

the production process without limiting 

the aggregate amount of production. 

This approach has been inherent in our 

past interpretation and application of 

section 111 and we maintain this 

interpretation in this rulemaking.468

While inclusion of building blocks 2 

and 3 is consistent with our 

interpretation of the statutory 

requirements, inclusion of building 

block 4 is not, and for that reason, we 

are declining to include building block 

in the BSER. Finally, we briefly note 

additional constraints that focus the 

BSER identified for new sources under 

section 111(b) on controls that assure 

that sources are well-controlled at the 

time of construction. 

b. System of emission reduction as a 

broad range of measures. 

(1) Plain meaning and context of 

‘‘system of emission reduction.’’ 

The phrase ‘‘system of emission 

reduction’’ appears in the definition of 

a ‘‘standard of performance’’ under CAA 

section 111(a)(1). That definition reads: 

a standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any nonair 

quality health and environmental impact and 

energy requirements) the Administrator 

determines has been adequately 

demonstrated. 

Pursuant to this definition, it is clear 

that a ‘‘system of emission reduction’’ 

serves as the basis for emission limits 

embodied by CAA section 111 

standards. For this reason, emission 

limits must be ‘‘achievable’’ through the 

‘‘application’’ of the ‘‘best’’ ‘‘system of 

emission reduction’’ ‘‘adequately 

demonstrated.’’ Under CAA section 

111(d)(1), such a limit is established for 

‘‘any existing source,’’ which is defined 

as any existing ‘‘building, structure, 

facility, or installation which emits or 

may emit any air pollutant.’’ 469

Although a ‘‘system of emission 

reduction’’ lays the groundwork for 

CAA section 111 standards, the term 

‘‘system’’ is not defined in the CAA. As 

a result, we look first to its ordinary 

meaning. 

Abstractly, the term ‘‘system’’ means 

a set of things or parts forming a 

complex whole; a set of principles or 

procedures according to which 

something is done; an organized scheme 

or method; and a group of interacting, 

interrelated, or interdependent 

elements.470 As a phrase, ‘‘system of 

emission reduction’’ takes a broad 

meaning to serve a singular purpose: It 

is a set of measures that work together 

to reduce emissions. 

When read in context, the phrase 

‘‘system of emission reduction’’ carries 

important limitations: because the 

‘‘degree of emission limitation’’ must be 

‘‘achievable through the application of 

the best system of emission reduction,’’ 

(emphasis added), the ‘‘system of 

emission reduction’’ must be limited to 

a set of measures that work together to 

reduce emissions and that are 

implementable by the sources 

themselves. 

As a practical matter, the ‘‘source’’ 

includes the ‘‘owner or operator’’ of any 

building, structure, facility, or 

installation for which a standard of 

performance is applicable. For instance, 

under CAA section 111(e), it is the 

‘‘owner or operator’’ of a source who is 

prohibited from operating ‘‘in violation 

of any standard of performance 

applicable to such source.’’ 471

Thus, a ‘‘system of emission 

reduction’’ for purposes of CAA section 

111(d) means a set of measures that 

source owners or operators can 

implement to achieve an emission 

limitation applicable to their existing 

source.472

In contrast, a ‘‘system of emission 

reduction’’ does not include actions that 

only a state or other governmental entity 

could take that would have the effect of 

reducing emissions from the source 

category, and that are beyond the ability 

of the affected sources’ owners/

operators to take or control. 

Additionally, actions that a source 

owner or operator could take that would 

not have the effect of reducing 

emissions from the source category, 

such as purchasing offsets, would also 

not qualify as a ‘‘system of emission 

reduction.’’ 

Building blocks 2 and 3 each fall 

within the meaning of a ‘‘system of 

emission reduction’’ because they 

consist of measures that the owners/

operators of the affected EGUs can 

implement to achieve their emission 

limits. In doing so, the affected EGUs 

will achieve the overall emission 

reductions the EPA identifies in this 

rule. We describe these building block 

2 and 3 measures in detail elsewhere in 

this rule, including the specific actions 

that owners/operators of affected EGUs 

can take to implement the measures. 

It should be noted that defining the 

scope of a ‘‘system of emission 

reduction’’ is not the end of our inquiry 

under CAA section 111(a)(1); rather, as 

noted above, a standard of performance 

must reflect the application of the ‘‘best 

system of emission reduction . . . 

adequately demonstrated.’’ (Emphasis 


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473 40 FR 53340, 53340 (Nov. 17, 1975) (EPA 

regulations implementing CAA section 111(d)). 474See S. Rep. No. 91–1196, at 20 (Sept. 17, 

1970), 1970 CAA Legis. Hist. at 420 (‘‘It should be 

noted that the emission standards for pollutants 

which cannot be considered hazardous (as defined 

in section 115 [i.e., the bill’s version of CAA section 

112] could be established under section 114 [i.e., 

the bill’s version CAA section 111]. Thus, there 

should be no gaps in control activities pertaining 

to stationary source emissions that pose any 

significant danger to public health or welfare.’’). 

475See S. Rep. No. 91–1196, at 20 (Sept. 17, 

1970), 1970 CAA Legis. Hist. at 420. 

476See S. Rep. No. 91–1196, at 9; 18–20, 1970 

CAA Legis. Hist. at 418–20. The Senate Committee 

Report identified 14 substances as subject to the 

provision that became section 111(d), four 

substances as hazardous air pollutants that would 

be regulated under the provision that became 

section 112, and 5 substances as criteria pollutants 

that would be regulated under the provisions that 

became sections 109–110 (and more ‘‘as knowledge 

increases’’). In particular, the Report recognized 

that in particular, relatively few air pollutants may 

qualify as 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). 

477See, e.g., Standards of Performance for New 

Stationary Sources and Emission Guidelines for 

Existing Sources: Hospital/Medical/Infectious 

Waste Incinerators, 62 FR 48348, 48359 (Sept. 15, 

1997); Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing 

Sources: Commercial and Industrial Solid Waste 

Incineration Units, 65 FR 75338, 75341 (Dec. 1, 

2000). 

478Although not defined under CAA section 111, 

the term was used in other provisions and defined 

in some of them. The term was defined under the 

CAA’s citizen suit provision. See 1970 CAA 

Amendments, Pub. L. 91–604, § 12, 84 Stat. 1676, 

1706 (Dec. 31, 1970) (defined as ‘‘(1) a schedule or 

timetable of compliance, emission limitation, 

standard of performance or emission standard, or 

(2) a control or prohibition respecting a motor 

vehicle fuel or fuel additive . . . . .’’). Congress also 

used it in the CAA’s NAAQS provisions and in 

CAA section 112. Under the CAA’s NAAQS 

provisions (i.e., the ‘‘Ambient Air Quality and 

Emission Standards’’ provisions), Congress directed 

the EPA to issue information on ‘‘air pollution 

control techniques,’’ and include data on ‘‘available 

technology and alternative methods of 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. 

added.) Thus, in determining the BSER, 

the Administrator must first determine 

whether the available systems of 

emission reduction are ‘‘adequately 

demonstrated,’’ based on the criteria, 

described above, set out by Congress in 

the legislative history and the D.C. 

Circuit in case law. After identifying the 

‘‘adequately demonstrated’’ systems of 

emission reduction, the Administrator 

then selects the ‘‘best’’ of these, based 

on several factors, including amount of 

emission reduction, cost, non-air quality 

health and environmental impact and 

energy requirements. Only after the 

Administrator weighs all of these 

considerations can she determine the 

BSER and, based on that, establish a 

standard of performance under CAA 

section 111(b) or an emission guideline 

under CAA section 111(d). 

For purposes of this final rule, it is 

not necessary to enumerate all of the 

types of measures that do or do not 

constitute a ‘‘system of emission 

reduction.’’ What is relevant is that 

building blocks 2 and 3 each qualify as 

part of the ‘‘system of emission 

reduction.’’ As noted, they focus on 

supply-side activities and they each 

constitute measures that the affected 

EGUs can implement that will allow 

those EGUs to achieve the degree of 

emission limitation that the EPA has 

identified based on those building 

blocks. Further, these building blocks 

also satisfy the other statutory criteria 

enumerated in CAA section 111(a)(1). 

(2) Other indications that the BSER 

provisions encompass a broad range of 

measures. 

The EPA’s plain meaning 

interpretation that the BSER provisions 

in CAA section 111(d)(1) and (a)(1) are 

designed to include a broad range of 

measures, including building blocks 2 

and 3, is supported by several other 

indications in the CAA and the 

legislative history of section 111. 

(a) Scope of CAA section 111(d)(1). 

First, the broad scope of CAA section 

111(d)(1) supports our interpretation of 

the BSER because a wide range of 

control measures is appropriate for the 

wide range of source categories and air 

pollutants covered under CAA section 

111(d). 

In the 1970 CAA Amendments, 

Congress established a regulatory regime 

for existing stationary sources of air 

pollutants that may be envisioned as a 

three-legged stool, designed to address 

‘‘three categories of pollutants emitted 

from stationary sources’’: (1) Criteria 

pollutants (identified under CAA 

section 109 and regulated under section 

110); (2) hazardous air pollutants 

(identified and regulated under section 

112); and (3) ‘‘pollutants that are (or 

may be) harmful to public health or 

welfare but are not’’ criteria or 

hazardous air pollutants.473 Congress 

enacted CAA section 111(d) to cover 

this third category of air pollutants and, 

in this sense, Congress designed it to 

apply to any air pollutants that were not 

otherwise regulated as toxics or NAAQS 

pollutants.474 This would include air 

pollutants that the EPA might later, 

when more information became 

available, designate as NAAQS or 

hazardous air pollutants, as well as air 

pollutants that Congress may not have 

been aware of at the time.475 In 

addition, the indications are that 

Congress expected CAA section 111(d) 

to be a significant source of regulatory 

activity, by some measures, more active 

than CAA section 112. This is evident 

because Congress expected that CAA 

section 111(d) would cover more air 

pollutants than either CAA section 109/ 

110 (criteria pollutants) or CAA section 

112 (hazardous air pollutants).476 In 

addition, in the 1990 CAA 

Amendments, Congress enacted CAA 

section 129 to achieve emission 

reductions from a major source category, 

solid waste incinerators, and established 

CAA section 111(d) as the basic 

mechanism for that provision. The EPA 

subsequently promulgated a number of 

CAA section 129/111(d) rulemakings.477

Finally, it should be noted that Congress 

designed CAA section 111(d) to cover a 

wide range of source categories— 

including any source category that the 

EPA identifies under subsection 

111(b)(1)(A) as meeting the criteria of, in 

general, causing or contributing 

significantly to air pollution that may 

reasonably be anticipated to endanger 

public health or welfare—along with the 

wide range of air pollutants. 

Because Congress designed CAA 

section 111(d) to cover a wide range of 

air pollutants—including ones that 

Congress may not have been aware of at 

the time it enacted the provision—and 

a wide range of industries, it is logical 

that Congress intended that the BSER 

provision, as applied to CAA section 

111(d), have a broad scope so as to 

accommodate the range of air pollutants 

and source categories. 

(b) Legislative history of CAA section 

111. 

(i) Breadth of ‘‘system of emission 

reduction.’’ 

The phrase ‘‘system of emission 

reduction,’’ particularly as applied 

under CAA section 111(d), should be 

broadly interpreted consistent with its 

plain meaning but also in light of its 

legislative history. The version of CAA 

section 111(d)(1) that Congress adopted 

as part of the 1970 CAA Amendments 

read largely as CAA section 111(d)(1) 

does at present, except that it required 

states to impose ‘‘emission standards’’ 

on any existing source. (Congress 

replaced that term with ‘‘standards of 

performance’’ in the 1977 CAA 

Amendments.) The 1970 CAA 

Amendments version of CAA section 

111(d)(1) neither defined ‘‘emission 

standards’’ nor imposed restrictions on 

the EPA in determining the basis for the 

emission standards.478

For new sources, CAA section 

111(b)(1)(B), as enacted in the 1970 

CAA Amendments (and as it largely still 


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479H.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. 

480S. 4358, § 6, 1970 Legis. Hist. at 554–55 

(emphasis added). 

481S. Rep. No. 91–1196, at 15–16 (Sept. 17, 1970), 

1970 CAA Legis. Hist. at 415–16 (emphasis added). 

482S. Rep. No. 91–1196, at 15–16 (Sept. 17, 1970), 

1970 CAA Legis. Hist. at 415–16 (emphasis added). 

483Notably, 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. 

484CAA section 111(a)(1) under the 1970 CAA 

Amendments (emphasis added). 

485Sen. Muskie, S. Consideration of H.R. Conf. 

Rep. No. 91–1783 (Dec. 17, 1970), 1970 CAA Legis. 

Hist. at 130. 

486CAA section 111(a)(1) (1977). 

487H.R. Rep. No. 95–294 (May 12, 1977), 1977 

CAA Legis. Hist. at 2659. 

488H.R. Rep. No. 95–294 (May 12, 1977), 1977 

CAA Legis. Hist. at 2659. 

489New Stationary Sources Performance 

Standards; Electric Utility Steam Generating Units, 

44 FR 33580, 33581–33582 (June 11, 1979). 

490H.R. Rep. No. 95–294, at 189 (May 12, 1977), 

1977 CAA Legis. Hist. at 2656. 

reads), required the EPA to promulgate 

‘‘standards of performance,’’ and 

defined that term, much like the present 

definition, as emission standards based 

on the ‘‘best system of emission 

reduction . . . adequately 

demonstrated.’’ This quoted phrase was 

not included in either the House or 

Senate versions of the provision, and, 

instead, was added during the joint 

conference between the House and 

Senate. The conference report 

accompanying the text offers no 

clarifications. 

The House and Senate bills do, 

however, provide some insights. The 

House bill, H.R. 17255, would have 

required new sources of non-hazardous 

air pollutants to ‘‘prevent and control 

such emissions to the fullest extent 

compatible with the available 

technology and economic feasibility, as 

determined by the Secretary.’’ 479 The 

Senate bill, S. 4358, would have 

established ‘‘Federal standards of 

performance for new sources,’’ which, 

in turn, were to ‘‘reflect the greatest 

degree of emission control which the 

Secretary determines to be achievable 

through application of the latest 

available control technology, processes, 

operating methods, or other 

alternatives.’’ 480 The Senate Committee 

Report explains that ‘‘performance 

standards should be met through 

application of the latest available 

emission control technology or through 

other means of preventing or controlling 

air pollution.’’ 481 This Report further 

elaborates that the term ‘‘standards of 

performance’’ 

refers to the degree of emission control which 

can be achieved through process changes, 

operation changes, direct emission control, or 

other methods. The Secretary should not 

make a technical judgment as to how the 

standard should be implemented. He should 

determine the achievable limits and let the 

owner or operator determine the most 

economic, acceptable technique to apply.482

Thus, the Senate bill clearly envisioned 

that standards of performance would 

not be based on a particular technology 

or even a particular method to prevent 

or control air pollution.483 This vision 

contrasted with the House bill, which 

would have restricted performance 

standards to economically feasible 

technical controls. 

Following the House-Senate 

Conference, the enacted version of the 

legislation defined a ‘‘standard of 

performance’’ to mean 

a standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction) the Administrator 

determines has been adequately 

demonstrated.484

While the phrase ‘‘system of emission 

reduction’’ was not discussed in the 

Conference Report, an exhibit titled 

‘‘Summary of the Provisions of 

Conference Agreement on the Clean Air 

Amendments of 1970’’ was added to the 

record during the Senate’s consideration 

of the Conference Report and sheds 

some light on the phrase. According to 

the summary, ‘‘[t]he agreement 

authorizes regulations to require that 

new major industry plants such as 

power plants, steel mills, and cement 

plants achieve a standard of emission 

performance based on the latest 

available control technology, processes, 

operating methods, and other 

alternatives.’’ 485 In light of this 

summary, the phrase ‘‘system of 

emission reduction’’ appears to blend 

the broad spirit of S. 4358 (which 

required the ‘‘latest available control 

technology, processes, operating 

methods, or other alternatives’’) with 

the cost concerns identified in H.R. 

17255 (which required consideration of 

‘‘economic feasibility’’ when 

establishing federal emission standards 

for new stationary sources). This history 

strongly suggests that Congress intended 

to authorize the EPA to consider a wide 

range of measures in calculating a 

standard of performance for stationary 

sources. At a minimum, there is no 

indication that Congress intended to 

preclude measures or actions such as 

the ones in building blocks 2 and 3 from 

the EPA’s assessment of the BSER. 

Notwithstanding this broad approach, 

as we discuss in the Legal 

Memorandum, the legislative history of 

the 1970 CAA Amendments also 

indicates that Congress intended that 

new sources be well-controlled at the 

source, in light of their expected lengthy 

useful lives. 

In 1977, Congress amended CAA 

section 111(a)(1) to limit the types of 

controls that could be the basis of 

standards of performance for new 

sources to technological controls. 

Congress was clear, however, that 

existing source standards, which were 

no longer developed as ‘‘emission 

standards,’’ would not be limited to 

technological measures. Specifically, 

the 1977 CAA Amendments revised 

CAA section 111(a)(1) to require all new 

sources to meet emission standards 

based on the reductions achievable 

through the use of the ‘‘best 

technological system of continuous 

emission reduction.’’ 486 According to 

the legislative history, [t]his mean[t] that 

new sources may not comply merely by 

burning untreated fuel, either oil or 

coal.’’ 487 The new requirement 

stemmed in part from Congress’s 

concern over the shocks that the country 

experienced during the 1973–74 Arab 

Oil Embargo, which led Congress to 

revise CAA section 111 to ‘‘encourage 

and facilitate the increased use of coal, 

and to reduce reliance (by new and old 

sources alike), upon petroleum to meet 

emission requirements.’’ 488 Imposing a 

new technological requirement (along 

with a new percentage reduction 

requirement) under CAA section 111 

was designed to ‘‘force new sources to 

burn high-sulfur fuel thus freeing lowsulfur fuel for use in existing sources 

where it is harder to control emissions 

and where low-sulfur fuel is needed for 

compliance.’’ 489 Congress nonetheless 

recognized that despite narrowing new 

source standards to the best 

‘‘technological system of continuous 

emission reduction,’’ many ‘‘innovative 

approaches may in fact reduce the 

economic and energy impact of 

emissions control,’’ and the 

Administrator should still be 

encouraged to consider other 

technologically based techniques for 

emissions reduction, including 

‘‘precombustion cleaning or treatment of 

fuels.’’ 490 This is discussed in more 

detail below. 

Despite these changes with respect to 

new sources, the 1977 CAA 

Amendments further reinforce the 


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491CAA section 111(a)(1)(C) under the 1977 CAA 

Amendments. 

492H.R. Rep. No. 95–294 (May 12, 1977), 1977 

CAA Legis. Hist. at 2662 (emphasis added). 

Congress also endorsed the EPA’s practice of 

establishing ‘‘emission guidelines’’ under CAA 

section 111(d). See H.R. Rep. No. 95–294 (May 12, 

1977), 1977 CAA Legis. Hist. at 2662 (‘‘The 

Administrator would establish guidelines as to 

what the best system for each such category of 

existing sources is. However, the state would be 

responsible for determining the applicability of 

such guidelines to any particular source or 

sources.’’). 

493Sen. Muskie, S. Consideration of the H.R. 

Conf. Rep. No. 95–564 (Aug. 4, 1977), 1977 CAA 

Legis. Hist. at 353. 

494 In 1977, Congress added a new substantive 

definition for ‘‘emission standard’’ generally 

applicable throughout the CAA. 1977 CAA 

Amendments, Public Law 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. 

495We 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. 

496There are numerous reasons to find that 

particular CAA section 111(b) standards of 

performance should be based on controls installed 

at the source at the time of new construction. This 

is due in part to the recognition that new sources 

have long operating lives over which initial capital 

costs can be amortized, as recognized in the 

legislative history for section 111. Thus, new 

construction is the preferred time to drive capital 

investment in emission controls. See, e.g., S. Rep. 

No. 91–1196, at 15–16, 1970 CAA Legis. Hist. at 416 

(‘‘[t]he overriding purpose of this section 

[concerning new source performance standards] 

would be to prevent new air pollution problems, 

and toward that end, maximum feasible control of 

new sources at the time of their construction is seen 

by the committee as the most effective and, in the 

long run, the least expensive approach.’’); see also 

1977 CAA Amendments, § 109, 91 Stat. at 700, 

(redefining, with respect to new sources, CAA 

section 111(a)(1) to reflect the best ‘‘technological 

system of continuous emission reduction’’ and 

adding CAA section 111(a)(7) to define this new 

term). However, as a result of the 1990 revisions to 

CAA section 111(a)(1), which replaced the phrase 

‘‘technological system of continuous emission 

reduction’’ with ‘‘system of emission reduction,’’ 

new source standards would not be restricted to 

being based on technological control measures. 

497See, e.g., comments by UARG at 31 (the 

building blocks other than building block 1 take a 

‘‘ ‘beyond-the-source’ approach’’ and 

‘‘impermissibly rely on measures that go beyond the 

boundaries of individual affected EGUs and that are 

not within the control of individual EGU owners 

and operators’’); comments by American Chemistry 

Council et al. (‘‘Associations’’) at 60–61 (EPA’s 

proposed BSER analysis is unlawful because it 

‘‘looks beyond the fence line of the fossil fuel-fired 

EGUs that are the subject of this rulemaking;’’ ‘‘the 

standard of performance must . . . be limited to the 

types of actions that can be implemented directly 

by an existing source within [the appropriate] class 

or category.’’). 

498 1977 CAA Amendments, § 109, 91 Stat. at 700; 

see also CAA section 111(a)(7). 

499H.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 

Continued 

notion that with respect to existing 

sources, the BSER was never intended 

to be narrowly applied. In 1977, 

Congress changed CAA section 

111(d)(1) to require that states adopt 

‘‘standards of performance’’ and made 

clear that such standards were to be 

based on the ‘‘best system of continuous 

emission reduction . . . adequately 

demonstrated,’’ 491 but generally 

maintained the breadth of that term. 

Although Congress inserted the word 

‘‘continuous’’ into the phrase, Congress 

explained that ‘‘standards in the Section 

111(d) state plan would be based on the 

best available means (not necessarily 

technological) for categories of existing 

sources to reduce emissions.’’ 492 This 

was intended to distinguish existing 

source standards from new source 

standards, for which ‘‘the requirement 

for [BSER] has been more narrowly 

redefined as best technological system 

of continuous emission 

reduction.’’ 493 494

In the 1990 CAA Amendments, 

Congress restored the 1970s vintage 

definition of a standard of performance 

as applied to both new and existing 

sources. With respect to existing 

sources, this had the effect of no longer 

requiring that the BSER be 

‘‘continuous.’’ 495 Further, nothing in 

the 1990 CAA Amendments or their 

legislative history indicates that 

Congress intended to 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 

technological process for production or 

operation by any source which is 

inherently low-polluting or 

nonpolluting,’’ CAA section 

111(a)(7)(A), or ‘‘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,’’ CAA 

section 111(a)(7)(B). 

That term continues to be used in 

reference to new sources in certain 

circumstances, under CAA section 

111(b), (h), and (j).496 However, it is not 

and never has been used to regulate 

existing sources. In this manner, the 

1990 CAA Amendments further 

reinforce the breadth and flexibility of 

the phrase ‘‘system of emission 

reduction,’’ particularly as it applies to 

existing sources under CAA section 

111(d). 

For these reasons, the 1970, 1977, and 

1990 legislative histories support the 

EPA’s interpretation in this rule that the 

term is sufficiently broad to encompass 

building blocks 2 and 3. 

(ii) Reliance on actions taken by other 

entities. 

The legislative history supports the 

EPA’s interpretation of ‘‘system of 

emission reduction’’ in another way as 

well: The legislative history makes clear 

that Congress intended that standards of 

performance for electric power plants 

could be based on measures 

implemented by other entities, for 

example, entities that ‘‘wash,’’ or 

desulfurize, coal (or, for oil-fired EGUs, 

that desulfurize oil). This legislative 

history is consistent with the EPA’s 

view that the ‘‘system of emission 

reduction’’ may include actions taken 

by an entity with whom the owner/

operator of the affected source enters 

into a contractual relationship as long as 

those actions allow the affected source 

to meet its emission limitation. By the 

same token, this legislative history 

directly refutes commenters’ assertions 

that the phrase ‘‘system of emission 

reduction’’ must not include actions 

taken by entities other than the affected 

sources.497

As noted above, in the 1977 CAA 

Amendments, Congress revised the 

basis for standards of performance for 

new fossil fuel-fired stationary sources 

to be a ‘‘technological system of 

continuous emission reduction,’’ 

including ‘‘precombustion cleaning or 

treatment of fuels.’’ 498 Precombustion 

cleaning or treatment reduces the 

amount of sulfur in the fuel, which 

means that the fuel can be combusted 

with fewer SO2 emissions, and that in 

turn means that the source can achieve 

a lower emission limit. Congress 

understood that these fuel cleaning 

techniques would not necessarily be 

accomplished at the affected source and, 

in revising CAA section 111(a)(1), 

wanted to ensure that such techniques 

would not be overlooked. For example, 

the 1977 House Committee report 

indicates that an assessment of the best 

technological system of continuous 

emission reduction for fossil fuel-fired 

power plants would include off-site or 

third-party pre-combustion techniques 

for reducing emissions at the source 

(‘‘e.g., various coal-cleaning 

technologies such as solvent refining, 

oil desulfurization at the refinery’’).499


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recognized in a regulatory analysis of new source 

performance standards for industrial-commercialinstitutional steam generating units that the 

technology ‘‘requires too much space and is too 

expensive to be employed at individual industrialcommercial-institutional steam generating units.’’ 

U.S. EPA, Summary of Regulatory Analysis for New 

Source Performance Standards: IndustrialCommercial-Institutional Steam Generating Units of 

Greater than 100 Million Btu/hr Heat Input, EPA– 

450/3–86–005, p. 4–4 (June 1986). 

500See U.S. EPA, Background Information for 

Proposed New-Source Performance Standards: 

Steam Generators, Incinerators, Portland Cement 

Plants, Nitric Acid Plants, Sulfuric Acid Plants, 

Office of Air Programs Tech. Rep. No. APTD–0711, 

p. 7 (Aug. 1971) (indicating the ‘‘desirability of 

setting sulfur dioxide standards that would allow 

the use of low-sulfur fuels as well as fuel cleaning, 

stack-gas cleaning, and equipment modifications’’ 

(emphasis added)). 

501 40 CFR 60.49b(n)(4); see also Amendments to 

New Source Performance Standards (NSPS) for 

Electric Utility Steam Generating Units and 

Industrial-Commercial-Institutional Steam 

Generating Units; Final Rule, 72 FR 32742 (June 13, 

2007). 

502By comparison, under the 1990 CAA 

Amendments, Congress substantially transformed 

CAA section 112 to be significantly more 

prescriptive in directing EPA rulemaking, which 

reflected Congress’s increased knowledge of 

hazardous air pollutants and impatience with the 

EPA’s progress in regulating. 

503 In the 1977 CAA Amendments, Congress 

applied the same broad drafting approach to the 

stratospheric ozone provisions it adopted in CAA 

sections 150–159. There, Congress authorized the 

EPA to determine whether, ‘‘in the Administrator’s 

judgment, any substance, practice, process, or 

activity may reasonably be anticipated to affect the 

stratosphere, especially ozone in the stratosphere, 

and such effect may reasonably be anticipated to 

endanger public health or welfare,’’ and then 

directed the EPA, if it made such a determination, 

to ‘‘promulgate regulations respecting the control of 

such process practice, process, or activity. . . .’’ 

CAA section 157(a). This provision does not further 

specify requirements for the regulations. 

504On 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. 

505Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 

440, 475 (1989) (Kennedy, J., concurring). 

Thus, the standard of performance 

reflecting the best technological system 

implementable by an affected source 

could be based, in part, on technologies 

used at off-site facilities owned and 

operated by third-parties. 

In the 1990 CAA Amendments, 

Congress eliminated many of the 

restrictions and other provisions added 

in the 1977 CAA Amendments by 

largely reinstating the 1970 CAA 

Amendments’ definition of ‘‘standard of 

performance.’’ Nevertheless, there is no 

indication that in doing so, Congress 

intended to preclude the EPA from 

considering coal cleaning by third 

parties (which had been considered 

within the scope of the best system of 

emission reduction even under the 1970 

CAA Amendments),500 and in fact, the 

EPA’s regulations promulgated after the 

1990 CAA Amendments continue to 

impose standards of performance that 

are based on third-party coal 

cleaning.501

(c) Consistency of a broad 

interpretation of CAA section 111 with 

the overall structure of the CAA. 

Interpreting CAA section 111(d)(1) 

and (a)(1) to authorize the EPA’s 

consideration of the building block 2 

and 3 measures is consistent with the 

overall structure of the CAA, 

particularly as it was amended in 1970, 

when Congress added CAA section 111 

in much the same form that it reads 

today. 

In the 1970 CAA Amendments, for the 

most part, and particularly for stationary 

source provisions, Congress painted 

with broad brush strokes, giving broad 

authority to the EPA or the states. That 

is, Congress established general 

requirements that were intended to 

produce stringent results, but gave the 

EPA or the states great discretion in 

fashioning the types of measures to 

achieve those results. 

For example, under CAA section 109, 

Congress authorized the EPA to 

promulgate national ambient air quality 

standards (NAAQS) for air pollutants, 

and Congress established general 

criteria and procedural requirements, 

but left to the EPA discretion to identify 

the air pollutants and select the 

standards. Under CAA section 110, 

Congress required the states to submit to 

the EPA SIPs, required that the plans 

attain the NAAQS by a date certain, and 

established procedural requirements, 

but allowed the states broad discretion 

in determining the substantive 

requirements of the SIPs. 

Under CAA section 111(b), Congress 

directed the EPA to list source 

categories that endanger public health 

or welfare and established procedural 

requirements, but did not include other 

substantive requirements, and instead 

gave the EPA broad discretion to 

determine the criteria for endangerment. 

Under CAA section 112, Congress 

required the EPA to regulate certain air 

pollutants and to set ‘‘emission 

standards’’ that meet general criteria, 

and established procedural 

requirements, but did not include other 

substantive requirements and, instead, 

gave the EPA broad discretion in 

identifying the types of pollutants and 

in determining the standards.502 By and 

large, Congress left these provisions 

intact in the 1977 CAA 

Amendments.503 504

Congress drafted the CAA section 

111(d) requirements in the 1970 CAA 

Amendments, and revised them in the 

1977 CAA Amendments, in a manner 

that is similar to the other stationary 

source requirements, just described, in 

CAA sections 109, 110, 111(b), and 112. 

The CAA section 111(d) requirements 

are broadly phrased, include procedural 

requirements but no more than very 

general substantive requirements, and 

give broad discretion to the EPA to 

determine the basis for the required 

emission limits and to the states to set 

the standards. It should be noted that 

this drafting approach is not unique to 

the CAA; on the contrary, Congress 

‘‘usually does not legislate by specifying 

examples, but by identifying broad and 

general principles that must be applied 

to particular factual instances.’’ 505

In light of this statutory framework, it 

is clear that Congress delegated to the 

EPA the authority to administer CAA 

section 111, including by authorizing 

the EPA to apply the ‘‘broad and general 

principles’’ contained in CAA section 

111(a)(1) to the particular circumstances 

we face today. 

(3) Comments and responses. 

While some commenters support the 

EPA’s interpretation of section 111 to 

authorize the inclusion of building 

blocks 2 and 3 in the BSER, other 

commenters assert that the emission 

standards must be based on measures 

that the sources subject to CAA section 

111—in this rule, the affected EGUs— 

apply to their own design or operations, 

and, as a result, in this rule, cannot 

include measures implemented at 

entities other than the affected EGUs 

that have the effect of reducing 

generation, and therefore emissions, 

from the affected EGUs. The 

commenters assert that various 

provisions in CAA section 111 make 

this limitation clear. We do not find 

those arguments persuasive. 

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 


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506Even under BART, the EPA is authorized to 

allow emissions trading between sources. See, e.g., 

40 CFR 51.308(e)(1) & (2); Util. Air Reg. Group v. 

EPA, 471 F.3d 1333 (D.C. Cir. 2006); Ctr. for Econ. 

Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 2005); and 

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

Cir. 1993). 

507 Industry commenters also acknowledged that 

it is the owner or operator that implements the 

control requirements. See UARG comment at 19 

(section 111(d) ‘‘provides for the regulation of 

individual emission sources through performance 

standards that are based on what design or process 

changes an individual source’s owner can integrate 

into its facility’’). 

508CAA 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.’’) 

preamble, the affected sources subject to 

this rule are fully able to meet their 

emission standards by undertaking the 

measures described in all three building 

blocks. Moreover, as discussed, the 

measures in building blocks 2 and 3 are 

highly effective in achieving CO2

emission reductions from these affected 

EGUs, given the unique characteristics 

of the industry. This reinforces the 

conclusion that the term ‘‘system of 

emission reduction’’ is broad enough to 

include these measures. 

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 low-emitting or 

nonpolluting.’’ (Emphasis added.) With 

respect to this portion of the definition 

(and ignoring the additional text, which 

includes ‘‘precombustion cleaning or 

treatment of fuels’’ and clearly 

encompasses off-site activities), it could 

be argued that between 1977 and 1990 

new source performance standards 

should be restricted to measures that 

could be integrated into the design or 

operation of a source. However, 

commenters’ assertion that the BSER 

must be limited in a similar fashion 

ignores the deliberate change in 1990 to 

restore the broader definition of a 

standard of performance (i.e., that it be 

based on the BSER and not the TSCER). 

In any case, the narrower scope of CAA 

section 111(a)(7) was never applicable 

to the regulation of existing sources 

under CAA section 111(d). 

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 such technology.’’ 506

(Emphasis added.) These provisions 

make clear that Congress knew how to 

constrain the basis for emission limits to 

measures that are integrated into the 

design or operation of the affected 

source, and that its choice to base CAA 

section 111(d)(1) and (a)(1) standards of 

performance on a ‘‘system of emission 

reduction’’ indicates Congress’ intent to 

authorize a broader basis for those 

standards. 

Some commenters also argue that 

other provisions in CAA section 111 

indicate that Congress intended that 

CAA section 111(d)(1) and (a)(1) be 

limited to measures that are integrated 

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 abovediscussed CAA section 407(b)(2) NOX

requirements. 

Second, the interpretations that 

commenters offer for these various 

provisions misapply the text. For 

example, commenters note that under 

CAA section 111(d)(1), (a)(3), and (a)(6), 

the standards of performance apply to 

‘‘any existing source,’’ and an ‘‘existing 

source’’ is defined to include ‘‘any 

stationary source,’’ which, in turn, is 

defined as ‘‘any building, structure, 

facility, or installation which emits or 

may emit any air pollutant.’’ 

Commenters assert that these 

applicability and definitional provisions 

indicate that the BSER provisions in 

CAA section 111(d)(1) and (a)(1) must 

be interpreted to require that the control 

measures must be integrated into the 

design or operations of the source itself. 

We disagree. These applicability and 

definitional provisions are jurisdictional 

in nature. Their purpose is simply to 

identify the types of sources whose 

emissions are to be addressed under 

CAA section 111(d), i.e., stationary 

sources, as opposed to other types of 

sources, e.g., mobile sources, whose 

emissions are addressed under other 

CAA provisions (such as CAA Title II). 

This purpose is made apparent by the 

terms of CAA section 111(a)(3), which 

contains two sentences (the second of 

which commenters seem to ignore). The 

first sentence provides: ‘‘The term 

‘stationary source’ means any building, 

structure, facility, or installation which 

emits or may emit any air pollutant.’’ 

The second sentence provides: ‘‘Nothing 

in subchapter II of this chapter relating 

to nonroad engines shall be construed to 

apply to stationary internal combustion 

engines.’’ This second sentence explains 

that stationary internal combustion 

engines are to be regulated under CAA 

section 111, and not Title II (relating to 

mobile sources), which confirms that 

the purpose of the definition of 

stationary source is jurisdictional in 

nature—to identify the emissions that 

are to be regulated under section 111, as 

opposed to other CAA provisions. 

These applicability and definitional 

provisions say nothing about the system 

of emission reduction—whether it is 

limited to measures integrated into the 

design or operation of the source itself 

or may be broader—that may form the 

basis of the standards for those 

emissions that are to be promulgated 

under CAA section 111. 

Third, this argument by commenters 

does not account for the commonsense 

proposition that it is the owner/operator 

of the stationary source, not the source 

itself, who is responsible for taking 

actions to achieve the emission rate, so 

that actions that the owner/operator is 

able to take should be considered in 

determining the appropriate standards 

for the source’s emissions. Again, it is 

common sense that buildings, 

structures, facilities, and installations 

can take no actions—only owners and 

operators can install and maintain 

pollution control equipment; only 

owners and operators can solicit 

precombustion cleaning or treatment of 

fuel services; and only owners and 

operators can apply for a permit or trade 

allowances.507 Other provisions in CAA 

section 111 make clear the role of the 

owner/operator. CAA section 111(e) 

provides that for new sources, the 

burden of compliance falls on the 

‘‘owner or operator.’’ 508 The same is 

necessarily true for existing sources. 

This supports the EPA’s view that the 

basis for whether a control measure 

qualifies as a ‘‘system of emission 

reduction’’ under CAA section 111(d)(1) 


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509For this same reason, the fact that CAA section 

111(h) authorizes the EPA to impose certain types 

of standards—such as, among others, work practice 

or operational standards—only in limited 

circumstances not present in this rulemaking, does 

not mean that the EPA cannot consider those same 

measures as the BSER in promulgating a standard 

of performance. 

510 It should also be noted that Title IV is limited 

to particular pollutants (i.e., SO2 and NOX) and 

particular sources—fossil fuel-fired EGUs—and as a 

result, lends itself to greater specificity about the 

types of control measures. Section 111(d), in 

contrast, applies to a wide range of source types, 

which, as discussed above, supports reading it to 

authorize a broad range of control measures. 511EPA 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.’’). 512American Electric Power Co. v. Connecticut, 

131 S. Ct. 2527, 2538 (2011) (‘‘AEP’’) (emphasis 

added). 

513S. 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). 

514See CAA section 404(f)(2)(B)(iii)(I) 

(conditioning a utility’s eligibility for certain 

allowances on implementing an energy 

conservation and electric power plan that evaluates 

a range of resources to meet expected future 

demand at least cost); see also S. Rep. No. 101–228, 

at 319–20 (Dec. 20, 1989) (recognizing that ‘‘utilities 

already engage in power-pooling arrangements to 

ensure maximum flexibility and efficiency in 

supplying power’’ to support the establishment of 

an allowance system under Title IV). 

515New York v. Federal Energy Regulatory 

Commission, 535 U.S. 1, at 7 (2002) (citing Brief for 

Respondent FERC 4–5). 

516 ‘‘Stack Heights Emissions Balancing Policy,’’ 

53 FR 480, 482 (Jan. 7, 1988). 

and (a)(1) is whether it is something that 

the owner/operator can implement in 

order to achieve the emissions standard 

assigned to the source—if so, the control 

measure should qualify as a ‘‘system of 

emission reduction’’—and not whether 

the control measure is integrated into 

the source’s own design or operation. 

Commenters also argue that CAA 

section 111(h), which authorizes 

‘‘design, equipment, work practice or 

operational standard[s]’’ (together, 

‘‘design standards’’) only when a 

source’s emissions are not emitted 

through a conveyance or cannot be 

measured, makes clear that CAA section 

111 standards of performance must be 

based on measures integrated into a 

source’s own design or operations. We 

disagree. CAA section 111(h) concerns 

the relatively rare situation in which an 

emission standard, which entails a 

numerical limit on emissions, is not 

appropriate because emissions cannot 

be measured, due either to the nature of 

the pollutant (i.e., the pollutant is not 

emitted through a conveyance) or the 

nature of the source category (i.e., the 

source category is not able to conduct 

measurements). CAA section 111(h) 

provides that in such cases, the EPA 

may instead impose design standards 

rather than establish an emission 

standard (i.e., the EPA can require 

sources to implement a particular 

design, equipment, work practice, or 

operational standard). When an 

emissions standard is appropriate, as in 

the present rule, CAA section 111(h) is 

silent as to what types of measures— 

whether limited to a source’s own 

design or operations—may be 

considered as the system of emission 

reduction.509 In any event, CAA section 

111(h) applies only to standards 

promulgated by the Administrator, and 

therefore appears by its terms to be 

limited to CAA section 111(b) 

rulemakings for new, modified, or 

reconstructed sources, not CAA section 

111(d) rulemakings for existing sources. 

Some commenters identify other 

provisions of CAA section 111 that, in 

their view, prove that CAA section 111 

is limited to control measures that are 

integrated within the design or 

operations of the source. We do not find 

those arguments persuasive, for the 

reasons discussed in the supporting 

documents for this rule. 

Commenters also argue, more 

generally, that Congress knew how to 

authorize control measures such as RE, 

as indicated by Congress’s inclusion of 

those measures in Title IV (relating to 

acid rain), so the fact that Congress did 

not explicitly include these measures in 

the BSER provisions of CAA section 

111(d)(1) and (a)(1) indicates that 

Congress did not intend that they be 

included as part of the BSER, and 

instead intended that the BSER be 

limited to measures integrated into the 

sources’ design or operations. This 

argument misses the mark. The 

provisions of CAA section 111(d)(1) and 

(a)(1) do not explicitly include any 

specific emission reduction measures— 

neither RE measures (like the ones 

Congress wanted to incentivize under 

Title IV), nor measures that are 

integrated into the sources’ design or 

operations (like the retrofit control 

measures Congress required under CAA 

section 407(b)). But this contrast with 

other CAA provisions does not mean 

that Congress did not intend the BSER 

to include any of those types of 

measures. Rather, this contrast supports 

viewing a ‘‘system of emission 

reduction’’ under CAA section 111 as 

sufficiently broad to encompass a wide 

range of measures for the purpose of 

emission reduction of a wide range of 

pollutants from a wide range of 

stationary sources.510

c. Deference to interpret the BSER to 

include building blocks 2 and 3. 

To the extent that it is not clear 

whether the phrase ‘‘system of emission 

reduction’’ may include the measures in 

building blocks 2 and 3, the EPA’s 

interpretation of CAA section 111(d) 

and (a) is reasonable 511 in light of our 

discretion to determine ‘‘whether and 

how to regulate carbon-dioxide 

emissions from power plants . . . .’’ 512

Our interpretation that a ‘‘system of 

emission reduction’’ for the affected 

EGUs may include building blocks 2 

and 3 is a reasonable construction of the 

statute for the reasons described above 

and in this section below. 

(1) Consistency of building blocks 2 

and 3 with the structure of the utility 

power sector. 

(a) Integration of the utility power 

sector. 

Certain characteristics of the utility 

power sector are of central importance 

for understanding why the measures of 

building blocks 2 and 3 qualify as part 

of the system of emission reduction. As 

discussed above, electricity is highly 

substitutable and the utility power 

sector is highly integrated, so much so 

that it has been likened to a ‘‘complex 

machine.’’ 513 Specifically, the utility 

power sector is characterized by 

physical, as well as operational, 

interconnections between electricity 

generators themselves, and between 

those generators and electricity users. 

Because of the physical properties of 

electricity and the current low 

availability of large scale electricity 

storage, generation and load (or use) 

must be instantaneously balanced in 

real time. As a result, the utility power 

sector is uniquely characterized by 

extensive planning and highly 

coordinated operation. These features 

have been present for decades, and in 

fact, over time, the sector has become 

more highly integrated. Another 

important characteristics of the utility 

power sector is that although the states 

have developed both regulated and deregulated 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. 

Congress,514 the Courts,515 the EPA in 

its regulatory actions,516 and states in 


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517See 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). 

518See Util. Air. Reg. Group v. EPA, 134 S. Ct. 

2427, 2441 (2014). 

519See 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.’’). 

520A number of utilities have climate mitigation 

plans. Examples include National Grid, http://

www2.nationalgrid.com/responsibility/how-weredoing/grid-data-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_

20140423_EXC_Exelon2020.aspx; PG&E, http:// 

Continued 

their regulatory actions 517 have 

recognized the integrated nature of the 

utility power sector. 

(b) Significance of integrated utility 

power sector for the BSER. 

The fungibility of electricity, coupled 

with the integration of the utility power 

sector, means that, assuming that 

demand is held constant, adding 

electricity to the grid from one generator 

will result in the instantaneous 

reduction in generation from other 

generators. Similarly, reductions in 

generation from one generator lead to 

the instantaneous increase in generation 

from other generators. Thus, the 

operation of individual EGUs is 

integrated and coordinated with the 

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 fuelfired EGUs can reduce their emissions 

by taking the actions in building blocks 

2 and 3. Specifically, fossil fuel-fired 

EGUs may generate or cause the 

generation of increased amounts of 

lower- or zero-emitting 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 

CO2.518

In light of these characteristics of the 

utility power sector, as well as the 

characteristics of CO2 pollution, it is 

reasonable for the EPA to reject an 

interpretation of the term ‘‘system of 

emission reduction’’ that would exclude 

building blocks 2 and 3 from 

consideration in this rule and instead 

restrict consideration to measures 

integrated into each individual affected 

source’s design or operation, especially 

since the record and other publicly 

available information makes clear that 

the measures in the two building blocks 

are effective in reducing emissions and 

are already widely used. 

As discussed above, no such 

restriction on the measures that can be 

considered part of a ‘‘system of emission 

reduction’’ is required by the statutory 

language, and the legislative history 

demonstrates that Congress intended an 

interpretation of the phrase broad 

enough to encompass building blocks 2 

and 3. The narrow interpretation 

advocated by some commenters would 

permit consideration only of potential 

CO2 reduction measures that are either 

more expensive than building blocks 2 

and 3 (such as the use of natural gas 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 called for by the statute— 

would be inconsistent with CAA section 

111’s specific requirement that 

standards be based on the ‘‘best’’ system 

of emission reduction and, as discussed 

below, would be inconsistent with 

Congressional design that the CAA be 

comprehensive and address the major 

environmental issues.519

The unique characteristics of the 

sector described above require 

coordinated action in the fundamental, 

primary function of EGUs—and in 

meeting current pollution control 

requirements to the extent that EGUs 

operate in dispatch systems that apply 

variable costs in determining dispatch— 

and affected EGUs 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 cost-effective manner, as 

further described below. CO2 is a global 

pollutant that is exceptionally wellsuited to emission reduction efforts 

optimized on a broad geographic scale 

rather than on a unit-by-unit basis. It is 

also clear from both comments and 

communications received through the 

Agency’s outreach efforts that affected 

EGUs will seek to use building blocks 2 

and 3 to achieve compliance with the 

emission standards set in the section 

111(d) plans following promulgation of 

this rule. For these reasons—and the 

additional reasons discussed below— 

interpreting ‘‘system of emission 

reduction’’ so as to allow consideration 

in this rule of only the individual pieces 

of the ‘‘complex machine,’’ and to forbid 

consideration of the ways in which the 

pieces actually fit and work together as 

parts of that machine, such as building 

blocks 2 and 3, cannot be justified. This 

is particularly so in light of the dilemma 

presented by the types of control 

options that commenters argue are the 

only ones authorized under section 

111(a)(1), which are controls that apply 

to the design or operation of the affected 

EGUs themselves. On the one hand, the 

control measures in building block 1 

yield only a small amount of emission 

reductions. On the other hand, control 

measures such as carbon capture and 

storage, or co-firing with natural gas, 

could yield much greater emission 

reductions, but are substantially more 

expensive than building blocks 2 and 3. 

(2) Current implementation of 

measures in building blocks 2 and 3. 

The requirement that the ‘‘system of 

emission reduction’’ be ‘‘adequately 

demonstrated’’ suggests that we begin 

our review under CAA section 111(d)(1) 

and (a)(1) with the systems that sources 

are already implementing to reduce 

their emissions. As noted above, fossil 

fuel-fired EGUs have long implemented, 

and are continuing to implement, the 

measures in building blocks 2 and 3 for 

various purposes, including for the 

purpose of reducing CO2 emissions 520— 


tkelley on DSK3SPTVN1PROD with BOOK 2
64770 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

www.pge.com/about/environment/pge/climate/; 

and Austin Energy, http://austinenergy.com/wps/

portal/ae/about/environment/austin-climateprotection-plan/!ut/p/a0/04_Sj9CPykssy0xPLMn

Mz0vMAfGjzOINjCyMPJwNjDzdzY0sDBzdnZ28

TcP8DAMMDPQLsh0VAU4fG7s!/. 

521See, 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). 

522 1990 CAA Amendments, § 403, 104 Stat. at 

2631 (requiring repeal of amendments to CAA 

section 111(a)(1) upon any cessation of 

effectiveness of CAA section 403(e), which requires 

new units to hold allowances for each ton of SO2

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. 

523 1990 CAA Amendments, § 406, 104 Stat. at 

2632–33; see also S. Rep. No. 101–228, at 282 

(industrial source emissions totaled 5.6 million tons 

of SO2 in 1985). 

524S. Rep. No. 101–228, at 345 (Dec. 20, 1989). 

525To 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). 

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. 

Some of the building block 

approaches to reducing emissions in the 

utility power sector were first tested 

around the time that Congress adopted 

the 1970 CAA Amendments.521 Over 

time, these techniques have become 

more established within the industry, 

and by the 1990 CAA Amendments, 

Congress based the Title IV acid rain 

program for existing fossil fuel-fired 

EGUs in part on the same measures that 

are considered here. 

(a) Overview. 

It is logical that in determining 

whether the ‘‘system of emission 

reduction’’ that Congress established in 

CAA section 111(d)(1) and (a)(1) is 

broad enough to include the measures 

in building blocks 2 and 3 as the basis 

for establishing emission guidelines for 

fossil fuel-fired EGUs, an inquiry should 

be made into the tools that Congress 

relied on in other CAA provisions to 

reduce emissions from those same 

sources. The most useful CAA provision 

to examine for this purpose is Title IV, 

which includes a nationwide cap-andtrade program under which coal-fired 

power plants must have allowances for 

their SO2 emissions. 

Title IV includes several signals that 

it is especially relevant for interpreting 

and implementing CAA section 111(d) 

for purposes of this rule. Title IV applies 

to most of the same sources that this 

rule applies to—existing coal-fired 

EGUs and other utility boilers, as well 

as NGCC units. In addition, Congress 

added Title IV in the 1990 CAA 

Amendments at the same time that 

Congress largely reinstated the 1970- 

vintage reading of section 111(a)(1) to 

adopt the currently applicable 

definition of a ‘‘standard of 

performance,’’ which is based on the 

‘‘best system of emission reduction . . . 

adequately demonstrated.’’ Moreover, 

Congress linked Title IV and CAA 

section 111 in certain respects. 

Specifically, Congress conditioned the 

revisions to CAA section 111(a)(1), i.e., 

eliminating the percentage reduction 

and most of the other limitations under 

the 1977 CAA Amendments, on the 

continued applicability of the Title IV 

SO2 cap, so that if the cap were 

eliminated, the changes would, by 

operation of law, also be eliminated, 

and the 1977 version of section 111(a)(1) 

would be reinstated.522 Additionally, 

Congress authorized the EPA to 

establish standards of performance for 

new and existing industrial (non-EGU) 

sources of SO2 emissions if emissions 

from these sources might exceed 1985 

levels and failed to decline at the 

expected rate.523 While industrial 

sources were not required to participate 

under Title IV—they could elect to do 

so, under CAA section 410(a)—Congress 

believed SO2 reductions from these 

sources were ‘‘an essential component 

of the reductions sought under [Title 

IV]’’ and intended that Title IV would 

‘‘assure[ ] that these projected 

reductions occur and will not be 

overcome by future growth in 

emissions.’’ 524 As such, Congress 

viewed federal standards of 

performance as the appropriate backstop 

to Title IV even for sources that could 

not otherwise be regulated under CAA 

section 111(d).525 Together, these 

signals suggest that it is reasonable for 

the EPA to consider Title IV when 

interpreting and implementing CAA 

section 111. 

For present purposes, the essential 

features of Title IV are that it regulates 

SO2 emissions from coal-fired EGUs by 

adopting a nationwide cap of 8.95 

million tons to be achieved through a 

tradable allowance system. As we 

explain below, the provisions of Title IV 

and its legislative history make clear 

that Congress based the stringency of 

the emission limitation requirement 

(8.95 million tons) and the overall 

structure of the approach (a cap-andtrade system) on Congress’s recognition 

that the affected EGUs had a set of tools 

available to them to reduce their 

emissions, including through a shift to 

lower emitting generation and use of RE, 

along with add-on controls and other 

measures. Thus, Title IV provides a 

close analogy to CAA section 111: 

Generation shift and RE were part of 

Congress’s basis for the Title IV 

emission requirements, and that is 

analogous to building blocks 2 and 3 

serving as part of the ‘‘system of 

emission reduction’’ that is the EPA’s 

basis for the section 111(d) emission 

guidelines. For this reason, the fact that 

in Title IV, Congress relied on 

generation shift and RE as the 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 finding that ‘‘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.’’ CAA section 401(a)(4) 

(emphasis added). Title IV then 

identifies as its ‘‘purposes,’’ ‘‘to reduce 

the adverse effects of acid deposition 

through reductions in annual emissions 

of sulfur dioxide . . . and nitrogen 

oxides,’’ as well as ‘‘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.’’ CAA 

section 401(b) (emphasis added). 

By its terms, this statement of Title 

IV’s purposes explicitly embraces the 

use of RE. Moreover, the legislative 


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526See S. Rep. No. 101–228, at 320 (Dec. 20, 

1989). 

527See S. Rep. No. 101–228, at 316 (Dec. 20, 

1989) (emphasis added). 

528CAA section 404(f)(2)(B)(i). 

529S. Rep. No. 101–228 (Dec. 20, 1989), 1990 

CAA Legis. Hist. at 8656. 

530S. Debates on Conf. Rep. to accompany S. 

1630, H.R. Rep. No. 101–952 (Oct. 27, 1990), 1990 

CAA Legis. Hist. at 1033–35 (statement of Senator 

Baucus, inserting ‘‘the Clean Air Conference 

Report’’ into the record). 

531H.R. Rep. No. 101–490, at 368–69; 674–76 

(May 17, 1990) (additional views of Reps. Markey 

and Moorhead) (‘‘We believe that H.R. 3030, as 

amended, will create a strong and effective 

incentive for utilities to immediately pursue energy 

conservation and renewable energy sources as key 

components of their acid rain control strategies.’’); 

see also Rep. Collins, H. Debates on H.R. Conf. Rep. 

No. 101–952 (Oct. 26, 1990), 1990 CAA Legis. Hist. 

at 1307 (‘‘The bottom line is that our Nation’s 

utilities and production facilities must reach 

beyond coal, oil, and fossil fuels. The focus must 

shift instead toward conservation and renewables 

such as hydropower, solar thermal, photovoltaics, 

geothermal, and wind. These clean sources and 

energy, available in virtually limitless supply, are 

the way of the future.’’). 

532 ‘‘Special Message to the Congress on 

Conservation and Restoration of Natural Beauty 

(Feb. 8, 1965). http://www.presidency.ucsb.edu/ws/ 

?pid=27285 (‘‘This generation has altered the 

composition of the atmosphere on a global scale 

through radioactive materials and a steady increase 

in carbon dioxide from the burning of fossil fuels.’’). 

533Testimony of Charles Johnson, Jr., 

Administrator of the Consumer Protection and 

Environmental Health Service (Administration 

Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 

CAA Legis. Hist. at 1381 (stating that ‘‘the carbon 

dioxide balance might result in the heating up of 

the atmosphere whereas the reduction of the radiant 

energy through particulate matter released to the 

atmosphere might cause reduction in radiation that 

reaches the earth’’). 

534 1970 CAA Legis. Hist. at 244, 257 S. Debate 

on S. 4358 (Sept. 21, 1970) (statement of Sen. 

Boggs) (replicating Chapter IV of the Council on 

Environmental Quality’s first annual report, which 

states, ‘‘the addition of particulates and carbon 

dioxide in the atmosphere could have dramatic and 

long-term effects on world climate.’’). 

535 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) 

(statement of Sen. Bumpers) (inserting into the 

record, ‘‘Summary of Statements Received from 

Professional Societies for the Hearings on Effects of 

Chronic Pollution (in the Subcommittee on the 

Environment and the Atmosphere),’’ which stated, 

‘‘there is near unanimity that carbon dioxide 

concentrations in the atmosphere are increasing 

rapidly. Though even the direction (warming or 

cooling) of the climate change to be caused by this 

is unknown, very profound changes in the balance 

of climate factors that determine temperature and 

rainfall on the earth are almost certain within 100 

years’’). 

536National 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). 

537S. Rep. No. 101–228, at 322 (Dec. 20, 1989), 

at 1990 Legis. Hist. at 8662 (‘‘In the last several 

years, the Committee has received extensive 

scientific testimony that increases in the humancaused emissions of carbon dioxide and other GHGs 

will lead to catastrophic shocks in the global 

climate system.’’); History, Jurisdiction, and a 

Summary of Activities of the Committee on Energy 

and Natural Resources During the 100th Congress, 

S. Rep. No. 101–138, at 5 (Sept. 1989); ‘‘Global 

Warming Has Begun, Expert Tells Senate,’’ New 

York Times, June 24, 1988, http://

www.nytimes.com/1988/06/24/us/global-warminghas-begun-expert-tells-senate.html. 

538Sen. Fowler, S. Debate on S. 1630 (Apr. 3, 

1990), 1990 CAA Legis. Hist. at 7106. 

539 1990 CAA Amendments, § 821, 104 Stat. at 

2699. 

history makes clear that the reference in 

the ‘‘findings’’ section quoted above to 

‘‘strategies and technologies’’ includes 

generation shift to lower-emitting 

generation. Specifically, the Senate 

Report stated that an ‘‘allowance 

system’’ 526 would encourage such 

‘‘technologies and strategies’’ as 

energy efficiency; enhanced emissions 

reduction or control technologies—like 

sorbent injection, cofiring with natural gas, 

integrated gasification combined cycles; fuelswitching and least-emissions dispatching in 

order to maximize emissions reductions. 527

Congress’s reliance on generation 

shifting and RE 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 RE. In 

CAA section 404(f) and (g), Congress set 

aside a special pool of allowances to 

encourage use of RE. In order to obtain 

a special allowance (which would 

authorize emissions from a coal-fired 

utility), an electric utility needed to pay 

for qualifying RE sources ‘‘directly or 

through purchase from another 

person.’’ 528 These measures confirm 

Congress’s recognition that RE 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 

measures, including shifting to loweremitting generation as well as reliance 

on RE. 

For example, the Senate Committee 

Report 529 and Senator Baucus,530 a 

member of the Senate Committee on 

Environment and Public Works and 

Chairman of the House and Senate 

Clean Air Conferees, both emphasized 

that affected EGUs could rely on, among 

other things, ‘‘least-emissions 

dispatching in order to maximize 

emissions reductions.’’ Similarly, 

statements supporting the RE reserve 

were included in the legislative history 

on the House side. 

We believe that this provision of the bill 

will establish a balanced and workable 

approach that will provide certainty for 

utility companies that are considering 

conservation and renewables, while at the 

same time strengthening the environmental 

goals of this legislation.531

(4) Reliance on RE measures to reduce 

CO2. 

The Title IV legislative history also 

makes clear that Congress viewed RE 

measures as a means to reduce CO2 for 

the purpose of mitigating climate 

change. By the time of the 1990 CAA 

Amendments, Congress had long been 

aware that emissions of CO2 and other 

GHGs put upward pressure on world 

temperatures and threatened to change 

the climate in destructive ways. In 1967, 

President Lyndon Johnson sent a letter 

to Congress recognizing that carbon 

dioxide was changing the composition 

of the atmosphere.532 The record for the 

1970 CAA Amendments include 

hearings 533 and a report by the National 

Academy of Sciences noting that carbon 

dioxide emissions could heat the 

atmosphere.534 A 1976 report noting the 

phenomenon was included in the record 

for the 1977 CAA Amendments.535 A 

1977 Report by the National Academy of 

Sciences warned that average 

temperatures would rise due to the 

burning of fossil fuel.536 By the time of 

the 1990 CAA Amendments, the 

dangers had become more clearly 

evident. Senate hearings beginning in 

1988 had presented testimony from Dr. 

James E. Hansen of the National 

Aeronautics and Space Administration 

and other scientists that described the 

dangers of climate change caused by 

anthropogenic carbon dioxide and other 

GHG emissions and asserted that as a 

result of those emissions, the climate 

was in fact already changing.537

In enacting the 1990 CAA 

Amendments, Congress identified 

reductions in carbon dioxide emissions 

as an important co-benefit of the 

reductions in coal use and stressed that 

the RE measures would achieve those 

reductions. Senator Fowler, the author 

of the provision that established a RE 

technology reserve within the allowance 

system, noted that RE technologies, 

‘‘can greatly reduce emissions of . . . 

global warming gases. That makes them 

a potent weapon against catastrophic 

climate change . . . .’’ 538

In addition, the 1990 CAA 

Amendments required EGUs covered by 

the monitoring requirements of the Title 

IV acid rain program to report their CO2

emissions.539


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540 70 FR 28606 (May 18, 2005). 

541 70 FR 28606, 28619 (May 18, 2005) (‘‘Under 

the CAMR scenario modeled by EPA, units [were] 

projected to meet their SO2 and NOX requirements 

and take additional steps to address the remaining 

[mercury] reduction requirements under CAA 

section 111, including adding [mercury]-specific 

control technologies (model applies [activated 

carbon injection]), additional scrubbers and 

[selective catalytic reduction], dispatch changes, 

and coal switching.’’). 

542New Jersey v. EPA, 517 F.3d 574, 583–84 (D.C. 

Cir. 2008), cert. denied sub nom. Util. Air Reg. 

Group v. New Jersey, 555 U.S. 1169 (2009). 

543 76 FR 48208 (Aug. 8, 2011). 

544 76 FR at 48452. 

545 76 FR at 48279–80. The exact mix of controls 

varied for different air pollutants and different time 

periods, but in all cases, shifting generation from 

higher to lower emitting units was one of the 

expected control strategies for the fossil fuel-fired 

power plants. Prior to CSAPR, the EPA promulgated 

two other transport rules, the NOX SIP Call (1998) 

and the Clean Air Interstate Rule (CAIR) (2005), 

which similarly established standards based on 

analysis of the availability and cost of emission 

reductions achievable through the use of add-on 

controls and generation shifting, and also 

authorized and encouraged the implementation of 

RE and demand-side EE measures. CAIR: 70 FR 

25162, 25165, 25256, 25279 (May 12, 2005) 

(allowing use of allowance set-asides for renewables 

and energy efficiency); NOX SIP Call: 63 FR 57356, 

57362, 57436, 57438, 57449 (Oct. 27, 1998) 

(authorizing and encouraging SIPs to rely on 

renewables and energy efficiency to meet the state 

budgets). 

546 134 S. Ct. 1584 (2014). 

547See, e.g., Guidance on SIP Credits for Emission 

Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures (Aug. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/

ereseerem_gd.pdf; Incorporating Emerging and 

Voluntary Measures in a State Implementation Plan 

(SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/ 

memoranda/evm_ievm_g.pdf. 

548CT 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/section_8.pdf). 

549 ‘‘Roadmap for Incorporating EE/RE Policies 

and Programs into SIPs/TIPs’’ (July 2012), http://

epa.gov/airquality/eere/manual.html. 

550States’ 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-reptto-epa-ee-in-naaqs-sip-roadmap-case-studies20140522.pdf. 

551 70 FR 25162, 25216–25225 (May 12, 2005). 

The EPA noted that its view was ‘‘based on the NOX

SIP Call experience.’’ Id. at 25217. 

(5) Other EPA actions that rely on the 

building block measures. 

Another indication that it is 

reasonable to interpret the CAA section 

111(d)(1) and (a)(1) provisions for the 

BSER to include the measures in 

building blocks 2 and 3 is that the EPA 

and states have relied on these measures 

to reduce emissions in a number of 

other CAA actions. 

For example, in 2005, the EPA 

promulgated a rule to control mercury 

emissions from fossil fuel-fired power 

plants under section 111(d): The Clean 

Air Mercury Rule (CAMR).540 The EPA 

established a nationwide cap-and-trade 

program that took effect in two phases: 

In 2010, the cap was set at 38 tons per 

year, and in 2018, the cap was lowered 

to 15 tons per year. The EPA expected, 

on the basis of modeling, that sources 

would achieve the second phase, 15-ton 

per year cap cost-effectively by choosing 

among a set of measures that included 

shifting generation to lower-emitting 

units.541 CAMR was vacated by the D.C. 

Circuit on other grounds,542 but it 

shows that in the only other section 

111(d) rule that the EPA attempted for 

affected EGUs, the EPA relied on 

shifting generation as part of the BSER 

in a CAA section 111(d) rulemaking for 

fossil fuel-fired EGUs. 

In 2011, the EPA promulgated the 

Cross State Air Pollution Rule 

(CSAPR),543 in which it set statewide 

emission budgets for NOX and SO2

emitted by fossil fuel-fired EGUs, and 

based those standards in part on shifts 

to lower-emitting generation. CSAPR 

established state-wide emissions 

budgets based on a range of costeffective actions that EGUs could take, 

and set the stringency of the deadlines 

for some required reductions in part 

because of the availability of ‘‘increased 

dispatch of lower-emitting generation 

which can be achieved by 2012.’’ 544

The EPA developed a federal 

implementation plan (FIP) that 

established a trading program to meet 

the state-wide emission budgets set by 

CSAPR. The EPA projected that sources 

would meet their emission reduction 

obligations by implementing a range of 

emission control approaches, including 

the operation of add-on controls, 

switches to lower-emitting coal, and 

‘‘changes in dispatch and generation 

shifting from higher emitting units to 

lower emitting units.’’ 545 The U.S. 

Supreme Court upheld CSAPR in EPA 

v. EME Homer City Generation, L.P.546

With respect to RE, in 2004, the EPA 

provided guidance to states for adopting 

attainment SIPs under CAA section 110 

that include RE measures.547 Some 

states have done so. For example, 

Connecticut included in its SIP 

reductions from solar photovoltaic 

installations.548 In 2012, the EPA 

provided additional guidance on this 

topic.549 In addition, the EPA has 

partnered with the Northeast States for 

Coordinated Air Use Management 

(NESCAUM) and three states (Maryland, 

Massachusetts, and New York) to 

identify opportunities for including RE 

in a SIP and to provide real-world 

examples and lessons learned through 

those states’ case studies.550

(6) Other rules that relied on actions 

by other entities. 

The EPA has promulgated numerous 

actions that establish control 

requirements for affected sources on the 

basis of actions by other entities or 

actions other than measures integrated 

into the design or operations of the 

affected sources. This section 

summarizes some of those actions. First, 

virtually all pollution control 

requirements require the affected 

sources to depend in one way or another 

on other entities, such as control 

technology manufacturers. Second, the 

EPA has promulgated numerous 

regulatory actions that are based on 

trading of mass-based emission 

allowances or rate-based emission 

credits, in which many sources meet 

their emission limitation requirements 

by purchasing allowances or credits 

from other sources that reduce 

emissions. 

(a) Third-party transactions. 

To reiterate, commenters argue that 

the ‘‘system of emission reduction’’ 

must be limited to measures taken by 

the affected source itself because only 

those measures are under the control of 

the affected source, as opposed to third 

parties, and therefore only those 

measures can assure that the affected 

source will achieve its emission limits. 

But this argument is belied by the fact 

that for a wide range of pollution 

control measures—including many that 

are indisputably part of a ‘‘system of 

emission reduction’’—affected sources 

are in fact dependent on third parties. 

For example, to implement any type of 

add-on pollution control equipment that 

is available only from a third-party 

manufacturer, the affected source is 

dependent upon that third party for 

developing and constructing the 

necessary controls, and for offering 

them for sale. Indeed, the affected 

sources may be dependent upon third 

parties to install (and in some cases to 

operate) the controls as well, and in fact, 

in the CAIR rule, the EPA established 

the compliance date based on the 

limited availability of the specialized 

workforce needed to install the controls 

needed by the affected EGUs.551 In 

addition, EGU owners and operators 

may be dependent on the actions of 

third parties to finance the controls and 

third-party regulators to assure the 

mechanism for repaying that financing. 

However, this dependence does not 

mean that the emission limit based on 

that equipment is not achievable. 

Rather, the fact that the owner or 

operator of the affected source can 

arrange with the various third parties to 


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552For example, in the enacting the acid rain 

program under CAA Title IV, Congress explicitly 

recognized that some sources would comply by 

purchasing allowances instead of implementing 

controls. S. Rep. No. 101–228, at 303 (Dec. 20, 

1989). Similarly, in promulgating the NOX SIP Call 

in 1998, the EPA stated, ‘‘Since EPA’s 

determination for the core group of sources is based 

on the adoption of a broad-based trading program, 

average cost-effectiveness serves as an adequate 

measure across sources because sources with high 

marginal costs will be able to take advantage of this 

program to lower their costs.’’ 63 FR at 57399 

(emphasis added). By the same token, in 

promulgating the Cross State Air Pollution Rule, the 

EPA stated, ‘‘the preferred trading remedy will 

allow source owners to choose among several 

compliance options to achieve required emission 

reductions in the most cost effective manner, such 

as installing controls, changing fuels, reducing 

utilization, buying allowances, or any combination 

of these actions.’’ 76 FR at 48272 (emphasis added). 

553See 44 FR 33580, 33597–33600 (taking into 

account ‘‘the amount of power that could be 

purchased from neighboring interconnected utility 

companies’’ and noting that ‘‘[a]lmost all electric 

utility generating units in the United States are 

electrically interconnected through power 

transmission lines and switching stations’’ and that 

‘‘load can usually be shifted to other electric 

generating units’’). 

554 47 FR 3767, 3768 (Jan. 27, 1982). 

acquire, install, and pay for the 

equipment means that emission limit is 

achievable. 

In this rule, as noted, the affected 

EGUs may, in many cases, implement 

the measures in building blocks 2 and 

3 directly, and, in other cases, 

implement those measures by engaging 

in market transactions with third parties 

that are as much within the affected 

EGUs’ control as engaging in market 

transactions with the range of third 

parties involved in pollution control 

equipment. By the same token, the 

market transactions that the affected 

EGUs engage in with third parties to 

implement the measures in building 

blocks 2 and 3 are comparable to the 

market transactions that affected EGUs 

engage in as part of their normal course 

of business, which include, among 

many examples, transactions with 

RTOs/ISOs or balancing authorities, 

entities in organized markets. 

(b) Emissions trading. 

Additional precedent that the ‘‘system 

of emission reduction’’ may include the 

measures in building blocks 2 and 3 and 

is not limited to measures that a source 

can integrate into its own design or 

operations, without being dependent on 

other entities, is found in the many 

rules that Congress has enacted or that 

the EPA has promulgated that allow 

EGUs and other sources to meet their 

emission limits by trading with other 

sources. In a trading rule, the EPA 

authorizes a source to meet its emission 

limit by purchasing mass-based 

emission allowances or rate-based 

emission credits generated from other 

sources, typically ones that implement 

controls that reduce their emissions to 

the point where they are able to sell 

allowances or credits. As a result, the 

availability of trading reduces overall 

costs to the industry by focusing the 

controls on the particular sources that 

have the least cost to implement 

controls. For present purposes, what is 

relevant is that in a trading program, 

some affected sources choose to meet 

their emission limits not by 

implementing emission controls 

integrated into their own design or 

operations, but rather by purchasing 

allowances or credits. These affected 

sources, therefore, are dependent on the 

actions of other entities, which are the 

ones that choose to meet their emission 

limits by implementing emission 

controls, which permits them to sell 

allowances or credits. They are 

dependent, however, in the same way 

that a source acquiring pollution control 

technology for the purposes of meeting 

a NSPS is dependent on a vendor of that 

technology to fulfill its contractual 

obligations. That is, the source operator 

purchasing a credit or an allowance is 

acquiring an equity in the technology or 

action applied to the credit-selling 

source for purposes of achieving a 

reduction in emissions occurring at the 

selling source. Trading programs have 

been commonplace under the CAA, 

particularly for EGUs, for decades. They 

include the acid rain trading program in 

Title IV of the CAA, the trading 

programs in the transport rules 

promulgated by the EPA under the 

‘‘good neighbor provision’’ of CAA 

section 110(a)(2)(D)(i)(I), the Clean Air 

Mercury Rule, and the regional haze 

rules. In each of these actions, the 

Congress or the EPA recognized that 

some of the affected EGUs would 

implement controls or take other actions 

that would lower their emissions and 

thereby allow them to sell allowances to 

other EGUs, which were dependent on 

the purchase of those allowances to 

meet their obligations.552 For the 

reasons just described, these trading 

rules refute commenters’ arguments for 

limiting the scope of the ‘‘system of 

emission reduction.’’ 

(c) NSPS rules for EGUs that depend 

on the integrated grid. 

The EPA has promulgated NSPS for 

EGUs that include requirements based 

on the fact that an EGU may reduce its 

generation, and therefore its emissions, 

because the integration of the grid 

allows another EGU to increase 

generation and thereby avoid 

jeopardizing the supply of electricity. 

For example, in 1979, the EPA finalized 

new standards of performance to limit 

emissions of SO2 from new, modified, 

and reconstructed EGUs. In evaluating 

the best system against concerns of 

electric service reliability, the EPA took 

into account the unique features of 

power transmission along the 

interconnected grid and the unique 

commercial relationships that rely on 

those features.553

Additionally, in 1982, the EPA 

recognized that utility turbines could 

meet a NOX emission limit without 

unacceptable economic consequences 

because ‘‘other electric generators on the 

grid can restore lost capacity caused by 

turbine down time.’’ 554 We describe the 

relevant parts of these rules in greater 

detail in the Legal Memorandum. 

(7) Consistency with the purposes of 

the Clean Air Act. 

Interpreting the term ‘‘system of 

emission reduction’’ broadly to include 

building blocks 2 and 3 (so that the 

‘‘best system of emission reduction . . . 

adequately demonstrated’’ may include 

those measures as long as they meet all 

of the applicable requirements) is also 

consistent with the purposes of the 

CAA. Most importantly, these purposes 

include protecting public health and 

welfare by comprehensively addressing 

air pollution, and, particularly, 

protecting against urgent and severe 

threats. In addition, these purposes 

include promoting pollution prevention 

measures, as well as the advancement of 

technology that reduces air pollution. 

(a) Purpose of protecting public health 

and welfare. 

The first provisions in the Clean Air 

Act set out the ‘‘Congressional findings 

and declaration of purpose.’’ CAA 

section 101. CAA section 101(a)(2) 

states the finding 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.’’ CAA section 

101(a)(3) states the finding 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.’’ CAA section 101(a) 

states the finding 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.’’ 

CAA section 101(b) next states ‘‘[t]he 

purposes’’ of the Clean Air Act. The first 

purpose is ‘‘to protect and enhance the 


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555H.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). 

556S. 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)). 

557See Dewey, Scott Hamilton, Don’t Breathe the 

Air: Air Pollution and U.S. Environmental Politics, 

1945–1970 (Texas A&M University Press 2000). 

558 1970 was a significant year in environmental 

legislation, but it was also marked as ‘‘a year of 

environmental concern.’’ Sen. Muskie, S. Debate on 

S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 

223. By mid-1970, Congress recognized that ‘‘[o]ver 

200 million tons of contaminants [were] spilled into 

the air each year in America . . . . And each year 

these 200 million tons of pollutants endanger the 

health of [the American] people.’’ Id. at 224. ‘‘Cities 

up and down the east coast were living under 

clouds of smog and daily air pollution alerts.’’ Sen. 

Muskie, S. Consideration of the Conference Rep. 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 124. Put 

simply, America faced an ‘‘environmental crisis.’’ 

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

1970 CAA Legis. Hist. at 224. The conference 

agreement, it was reported, ‘‘faces the air pollution 

crisis with urgency and in candor. It makes hard 

choices, provides just remedies, requires stiff 

penalties.’’ Sen. Muskie, S. Consideration of the 

Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. 

Hist. at 123. ‘‘[I]t represents [Congress’] best efforts 

to act with the knowledge available . . . in an 

affirmative but constructive manner.’’ Id. at 150. 

559See Dewey, Scott Hamilton, Don’t Breathe the 

Air: Air Pollution and U.S. Environmental Politics, 

1945–1970 (Texas A&M University Press 2000) at 

230 (‘‘By the mid-1960s, top federal officials 

showed an increasing sense of alarm regarding the 

health effects of polluted air. In June, 1966, 

Secretary of Health, Education, and Welfare John 

W. Gardner testified before the Muskie 

subcommittee: ‘‘We believe that air pollution at 

concentrations which are routinely sustained in 

urban areas of the United States is a health hazard 

to many, if not all, people.’’). 

560Train v. NRDC, 421 U.S. 60, 64 (1975). 

561S. Rep. No. 91–1196, at 20 (Sept. 17, 1970), 

1970 CAA Legis. Hist. at 420 (discussing section 

114 of the Senate Committee bill, which was the 

basis for CAA section 111(d)). Note that in the 1977 

CAA Amendments, the House Committee Report 

made a similar statement. H.R. Rep. No. 95–294, at 

42 (May 12, 1977), 1977 CAA Legis. Hist. at 2509 

(discussing a provision in the House Committee bill 

that became CAA section 122, requiring EPA to 

study and then take action to regulate radioactive 

air pollutants and three other air pollutants). 

562Statement 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. 

563H.R. Rep. No. 101–490, at 144 (May 17, 1990). 

564H.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. 

quality of the Nation’s air resources so 

as to promote the public health and 

welfare and the productive capacity of 

its population.’’ CAA section 101(b)(1). 

The second is ‘‘to initiate and accelerate 

a national research and development 

program to achieve the prevention and 

control of air pollution.’’ CAA section 

101(b)(2). The third is ‘‘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.’’ CAA 

section 101(b)(3). The fourth is ‘‘to 

encourage and assist the development 

and operation of regional air pollution 

prevention and control programs.’’ CAA 

section 101(c) adds that ‘‘[a] primary 

goal of this Act is to encourage or 

otherwise promote reasonable Federal, 

State, and local governmental actions, 

consistent with the provisions of this 

Act, for pollution prevention.’’ 

As just quoted, these provisions are 

explicit that the purpose of the CAA is 

‘‘to protect and enhance the quality of 

the Nation’s air resources so as to 

promote the public health and welfare 

and the productive capacity of its 

population.’’ Moreover, Congress 

designed the CAA to be ‘‘the 

comprehensive vehicle for protection of 

the Nation’s health from air 

pollution’’ 555 and, in fact, designed 

CAA section 111(d) to address air 

pollutants not covered under other 

provisions, specifically so that ‘‘there 

should be no gaps in control activities 

pertaining to stationary source 

emissions that pose any significant 

danger to public health or welfare.’’ 556

Furthermore, in these purpose 

provisions, Congress recognized that 

while pollution prevention and control 

are the primary responsibility of the 

States, ‘‘federal leadership’’ would be 

essential. 

At its core, Congress designed the 

CAA to address urgent and severe 

threats to public health and welfare. 

This purpose is evident throughout 

1970 CAA Amendments, which 

authorized stringent remedies that were 

necessary to address those problems. By 

1970, Congress viewed the air pollution 

problem, which had been worsening 

steadily as the nation continued to 

industrialize and as automobile travel 

dramatically increased after World War 

II,557 as nothing short of a national 

crisis.558 With the 1970 CAA 

Amendments, Congress enacted a 

stringent response, designed to match 

the severity of the problem. At the same 

time, Congress did not foreclose the 

EPA’s ability to address new 

environmental concerns; in fact, 

Congress largely deferred to the EPA’s 

expertise in identifying pollutants and 

sources that adversely affect public 

health or welfare. In doing so, Congress 

authorized the EPA to establish national 

ambient air quality standards for the 

most pervasive air pollutants— 

including the precursors for the choking 

smog that blanketed urban areas 559—to 

protect public health with an ample 

margin of safety. Disappointed that the 

states had not taken effective action to 

that point to curb air pollution, 

‘‘Congress reacted by taking a stick to 

the States’’ 560 and including within the 

1970 CAA Amendments both the 

requirement that the states develop 

plans to assure that their air quality 

areas would meet those standards by no 

later than five years, and the threat of 

imposition of federal requirements if the 

states did not timely adopt the requisite 

plans. Congress also required the EPA to 

establish standards for hazardous air 

pollutants that could result in shutting 

sources down. Congress added stringent 

controls on automobiles, overriding 

industry objections that the standards 

were not achievable. In addition, 

Congress added CAA section 111(b), 

which required the EPA to list 

categories based on harm to public 

health and regulate new sources in 

those categories. Congress then designed 

CAA section 111(d) to assure, as the 

Senate Committee Report for the 1970 

CAA Amendments noted, that ‘‘there 

should be no gaps in control activities 

pertaining to stationary source 

emissions that pose any significant 

danger to public health or welfare.’’ 561

Similarly, the 1977 and 1990 CAA 

Amendments were also designed to 

respond to new and/or pressing 

environmental issues. For example, in 

1977 then-EPA Administrator Costle 

testified before Congress that the 

expected increase in coal use (in 

response to various energy crises, 

including the 1973–74 Arab Oil 

Embargo) ‘‘will make vigorous and 

effective control even more urgent.’’ 562

Similarly, by 1990, Congress recognized 

that ‘‘many of the Nation’s most 

important air pollution problems [had] 

failed to improve or [had] grown more 

serious.’’ 563 Indeed, President George H. 

W. Bush said that ‘‘ ‘progress has not 

come quickly enough and much remains 

to be done.’ ’’ 564

Climate change has become the 

nation’s most important environmental 

problem. We are now at a critical 

juncture to take meaningful action to 

curb the growth in CO2 emissions and 

forestall the impending consequences of 

prior inaction. CO2 emissions from 

existing fossil fuel-fired power plants 


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565 In addition, as we have noted, in designing the 

1970 CAA Amendments, Congress was aware that 

carbon dioxide increased atmospheric 

temperatures. In 1970, when Congress learned that 

‘‘the carbon dioxide balance might result in the 

heating up of the atmosphere’’ and that particulate 

matter ‘‘might cause reduction in radiation,’’ the 

Nixon Administration assured Congress that 

‘‘[w]hat we are trying to do, however, in terms of 

our air pollution effort should have a very salutary 

effect on either of these.’’ Testimony of Charles 

Johnson, Jr., Administrator of the Consumer 

Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House 

Subcommittee on Public Health and Welfare (Mar. 

16, 1970), 1970 CAA Legis. Hist. at 1381. Many 

years later, scientific consensus has formed around 

the particular causes and effects of climate change; 

and the tools put in place in 1970 can be read fairly 

to address these concerns. 

566This final rule is also consistent with the 

CAA’s purpose of protecting health and welfare. For 

example, the CAA authorizes the EPA to regulate 

air pollutants as soon as the EPA can determine that 

those pollutants pose a risk of harm, and not to wait 

until the EPA can prove that those pollutants 

actually cause harm. See H.R. Rep. No. 95–294, at 

49 (May 12, 1977), 1977 CAA Legis. Hist. at 2516 

(describing the CAA as being designed . . . to 

assure that regulatory action can effectively prevent 

harm before it occurs; to emphasize the 

predominant value of protection of public health’’). 

The protective spirit of the CAA extends to the 

present rule, in which the EPA regulates on the 

basis of building blocks 2 and 3 because the range 

of available and cost-effective measures in those 

building blocks achieves more pollution reduction 

than building block 1 alone. Indeed, add-on 

controls that are technically capable of reducing 

CO2 emissions at the scale necessitated by the 

severity of the environmental risk—for example, 

CCS technology—are not as cost-effective as 

building blocks 2 and 3 on an industry-wide basis, 

and while the costs of the add-on controls can be 

expected to be reduced over time, it is not 

consonant with the protective spirit of the CAA to 

wait. 

567See 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). 

568Section 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. 

569See 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’’). 

570See S. Rep. No. 91–1196, at 15 (‘‘The 

maximum use of available means of preventing and 

controlling air pollution is essential to the 

elimination of new pollution problems’’). 

571See Sierra Club v. Costle, 657 F.2d at 351 

(upholding a standard of performance designed to 

promote the use of an emerging technology). 

are by far the largest source of stationary 

source emissions. They emit almost 

three times as much CO2 as do the next 

nine stationary source categories 

combined, and approximately the same 

amount of CO2 emissions as all of the 

nation’s mobile sources. The only 

controls available that can reduce CO2

emissions from existing power plants in 

amounts commensurate with the 

problems they pose are the measures in 

building blocks 2 and 3, or far more 

expensive measures such as CCS. 

Thus, interpreting the ‘‘system of 

emission reduction’’ provisions in CAA 

section 111(d)(1) and (a)(1) to allow the 

nation to meaningfully address the 

urgent and severe public health and 

welfare threats that climate change pose 

is consistent with what the CAA was 

designed to do.565 This interpretation is 

also consistent with the cooperative 

purpose of section 111(d) to assure that 

the CAA comprehensively address those 

threats through the mechanism of state 

plans, where the states assume primary 

responsibility under federal leadership. 

See King v. Burwell, 576 U.S. (2015), No. 

14–114 (2015), slip op. at 15 (‘‘We 

cannot interpret federal statutes to 

negate their own stated purposes’’ 

(quoting New York State Dept. of Social 

Servs. v. Dublino, 413 U.S. 405, 419–20 

(1973)); id. at 21 (‘‘A fair reading of 

legislation demands a fair 

understanding of the legislative 

plan.’’).566

(b) Purpose of encouraging pollution 

prevention. 

Interpreting ‘‘system of emission 

reduction’’ to include building blocks 2 

and 3 is also consistent with the CAA’s 

purpose to encourage pollution 

prevention. CAA section 101(c) states 

that ‘‘[a] primary goal of [the CAA] is to 

encourage or otherwise promote 

reasonable federal, state, and local 

governmental actions, consistent with 

the provisions of this chapter, for 

pollution prevention.’’ Indeed, in the 

U.S. Code, in which the CAA is codified 

as chapter 85, the CAA is entitled, ‘‘Air 

Pollution Prevention and Control.’’ 567

CAA section 101(a)(3) describes ‘‘air 

pollution prevention’’ as ‘‘the reduction 

or elimination, through any measures, of 

the amount of pollutants produced or 

created at the source’’. (Emphasis 

added.) The reference to ‘‘any 

measures’’ highlights the breadth of 

what Congress considered to be 

pollution prevention, that is, any and all 

measures that reduce or eliminate 

pollutants at the source.568

The measures in building blocks 2 

and 3 qualify as ‘‘pollution prevention’’ 

measures because they are ‘‘any 

measures’’ that ‘‘reduc[e] or eliminate[e] 

. . . the amount of pollutants produced 

or created at the [fossil fuel-fired 

affected] source[s].’’ Thus, consistent 

with the CAA’s primary goals, it is 

therefore reasonable to interpret a 

‘‘system of emission reduction,’’ as 

including the pollution prevention 

measures in building blocks 2 and 3. 

(c) Purpose of advancing technology 

to control air pollution. 

This final rule is also consistent with 

CAA section 111’s purpose of promoting 

the advancement of pollution control 

technology based on the expectation 

that American industry will be able to 

develop innovative solutions to the 

environmental problems. 

The legislative history and case law of 

CAA section 111 identify three different 

ways that Congress designed CAA 

section 111 to authorize standards of 

performance that promote technological 

improvement: (i) The development of 

technology that may be treated as the 

‘‘best system of emission reduction . . . 

adequately demonstrated;’’ under CAA 

section 111(a)(1); 569 (ii) the expanded 

use of the best demonstrated 

technology; 570 and (iii) the 

development of emerging technology.571

This rule is consistent with the second 

of those ways—it expands the use of the 

measures in building blocks 2 and 3, 

which are already established and 

provide substantial reductions at 

reasonable cost. As discussed below, the 

use of the measures in these building 

blocks will be most fully expanded 

when organized markets develop, and 

our expectation that those markets will 

develop is consistent with the 

Congress’s view, just described, that 

CAA section 111 should promote 

technological innovation. 

This final rule is also consistent with 

Congress’s overall view that the CAA 

Amendments as a whole were designed 

to promote technological innovation. In 

enacting the CAA, Congress articulated 

its expectation that American industry 

would be creative and come up with 

innovative solutions to the urgent and 

severe problem of air pollution. This is 

manifest in the well-recognized 

technology-forcing nature of the CAA, 

and was expressed in numerous, 

sometimes ringing, statements in the 

legislative history about the belief that 

American industry will be able to 

develop the needed technology. For 

example, in the 1970 floor debates, 

Congress recalled that the nation had 

put a man on the moon a year before 

and had won World War II a quarter 

century earlier, and attributed much of 

the credit for those singular 

achievements to American industry and 

its ability to be productive and 

innovative. Congress expressed 

confidence that American industry 


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572Sen. Muskie, S. Debates on S. 4358 (Sept. 21, 

1970), 1970 CAA Legis. Hist. at 227 (‘‘At the 

beginning of World War II industry told President 

Roosevelt that his goal of 100,000 planes each year 

could not be met. The goal was met, and the war 

was won. And in 1960, President Kennedy said that 

America would land a man on the moon by 1970. 

And American industry did what had to be done. 

Our responsibility in Congress is to say that the 

requirements of this bill are what the health of the 

Nation requires, and to challenge polluters to meet 

them.’’). See Blaime, A.J., The Arsenal of 

Democracy: FDR, Detroit, and an Epic Quest to Arm 

an America at War (Houghton Mifflin Harcourt 

2014); Carew, Michael G., Becoming the Arsenal: 

The American Industrial Mobilization for World 

War II, 1938–1942 (University Press of America, 

Inc. 2010). 

573UARG comment at 31. See id. at 18, 29, 49. 

This comment appears to be a reference to the 

Supreme Court’s statement in UARG. See Util. Air 

Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014). 

574Commenters offered hypothetical examples to 

illustrate their concerns over precedential effects, 

discussed below. Some commenters objected that 

our proposed interpretation of the BSER failed to 

include limiting principles. In the Legal 

Memorandum, we note that the statutory 

constraints discussed in this section of the 

preamble constitute limits on the type of the BSER 

that the EPA is authorized to determine. 

could meet the challenges of developing 

air pollution controls as well.572

(d) Response to commenters 

concerning purpose. 

Commenters have stated that the 

proposed rule ‘‘would transform CAA 

section 111 into something untethered 

to its statutory language and 

unrecognizable to the Congress that 

created it.’’ 573 Commenters with this 

line of comments focused on the 

ramifications of building block 4, which 

the EPA has decided does not belong in 

BSER using EPA’s historical 

interpretation of BSER. Regardless of 

whether the comments are accurate with 

respect to building block 4 measures, 

they are certainly not accurate with 

respect to the three building blocks that 

the EPA is defining as the BSER. This 

rule would be recognizable to the 

Congresses that created and amended 

CAA section 111 and is carefully 

fashioned to the statutory text in CAA 

section 111(d) and (a)(1). This final rule 

would be recognizable to the Congress 

that adopted CAA section 111 in 1970 

as part of a bold, far-reaching law 

designed to address comprehensively an 

air pollution crisis that threatened the 

health of millions of Americans; to have 

EPA and the States work cooperatively 

to develop state-specific approaches to 

address a national problem; to challenge 

industry to meet that crisis with creative 

energy; and to give the EPA broad 

authority—under section 111 and other 

provisions—to craft the needed 

emission limitations. This final rule 

would be recognizable to the Congress 

that revised CAA section 111 in 1977 to 

explicitly authorize that standards be 

based on actions taken by third parties 

(fuel cleaners). And this final rule 

would be recognizable to the Congress 

that revised CAA section 111 in 1990 to 

be linked to the Acid Rain Program that 

Congress adopted at the same time, 

which regulated the same industry 

(fossil fuel-fired EGUs) through some of 

the same measures (generation shifts 

and RE), and that explicitly 

acknowledged that those measures (RE) 

would also reduce CO2 and thereby 

address the dangers of climate change. 

To reiterate, for the reasons explained in 

this preamble, this rule is grounded in 

our reasonable interpretation of CAA 

section 111(d) and (a)(1). 

(8) Constraints on the BSER— 

treatment of building block 4 and 

response to comments concerning 

precedents. 

Although the BSER provisions are 

sufficiently broad to include, for 

affected EGUs, the measures in building 

blocks 2 and 3, they also incorporate 

significant constraints on the types of 

measures that may be included in the 

BSER. We discuss those constraints in 

this section. These constaints explain 

why we are not including building 

block 4 in the BSER. In addition, these 

constraints explain why our reliance on 

building blocks 2 and 3 will have 

limited precedential effect for other 

rulemakings, and serve as our basis for 

responding to commenters who 

expressed concern that reliance on 

building blocks 2 and 3 would set a 

precedent for the EPA to rely on similar 

measures in promulgating future air 

pollution controls for other sectors.574

As discussed above, the emission 

limits in the CAA section 111(d) 

emission guidelines that this rule 

promulgates are based on the EPA’s 

determination, for the affected EGUs, of 

the ‘‘system of emission reduction’’ that 

is the ‘‘best,’’ taking into account ‘‘cost’’ 

and other factors, and that is 

‘‘adequately demonstrated.’’ Those 

components include certain 

interpretations and applications and 

provide constraints on the types of 

measures or controls that the EPA may 

determine to include in the BSER. 

(a) Emission reductions from affected 

sources. 

The first constraint is that the BSER 

must assure emission reductions from 

the affected sources. Under section 

111(d)(1), the states must submit state 

plans that ‘‘establish[] standards of 

performance for any existing source,’’ 

and, under section 111(a)(1) and the 

EPA’s implementing regulations, those 

standards are informed by the EPA’s 

determination of the best system of 

emission reduction adequately 

demonstrated. Because the emission 

standards must apply to the affected 

sources, actions taken by affected 

sources that do not result in emission 

reductions from the affected sources— 

for example, offsets (e.g., the planting of 

forests to sequester CO2)—do not qualify 

for inclusion in the BSER. Building 

blocks 2 and 3 achieve emission 

reductions from the affected EGUs, and 

thus are not precluded under this 

constraint. 

(b) Controls or measures that affected 

EGUs can implement. 

The second constraint is that because 

the affected EGUs must be able to 

achieve their emission performance 

rates through the application of the 

BSER, the BSER must be controls or 

measures that the EGUs themselves can 

implement. Moreover, as noted, the D.C. 

Circuit has established criteria for 

achievability in the section 111(b) case 

law; e.g., sources must be able to 

achieve their standards under a range of 

circumstances. If those criteria are 

applicable in a section 111(d) rule, the 

BSER must be of a type that allows 

sources to meet those achievability 

criteria. As noted, under this rule, 

affected EGUs can achieve their 

emission performance rates in the 

various circumstances under which they 

operate, through the application of the 

building blocks. 

(c) ‘‘Adequately demonstrated.’’ 

The third constraint is that the system 

of emission reduction that the EPA 

determines to be the best must be 

‘‘adequately demonstrated.’’ To qualify 

as the BSER, controls and measures 

must align with the nature of the 

regulated industry and the nature of the 

pollutant so that implementation of 

those controls or measures will result in 

emission reductions from the industry 

and allow the sources to achieve their 

emission performance standards. The 

history of the effectiveness of the 

controls or other measures, or other 

indications of their effectiveness, are 

important in determining whether they 

are adequately demonstrated. 

More specifically, the application of 

building blocks 2 and 3 to affected EGUs 

has a number of unique characteristics. 

Building blocks 2 and 3 entail the 

production of the same amount of the 

same product—electricity, a fungible 

product that can be produced using a 

variety of highly substitutable 

generation processes—through the 

cleaner (that is, less CO2-intensive) 

processes of shifting dispatch from 

steam generators to existing NGCC 

units, and from both steam generators 

and NGCC units to renewable 

generators. 


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575UARG comment at 2–3. 

576 In any event, it is questionable whether 

measures such as those hypothesized by the 

commenters would be consistent with the 

provisions of Title II. 

577See Lignite Energy Council v. EPA, 198 F.3d 

930, 933 (D.C. Cir. 1999). 

578See, e.g., 44 FR 33580, at 33599 (June 11, 

1979). In this rulemaking, the EPA recognized the 

ability of the integrated grid to minimize power 

disruptions: ‘‘When electric load is shifted from a 

Continued 

The physical properties of electricity 

and the highly integrated nature of the 

electricity system allow the use of these 

cleaner processes to generate the same 

amount of electricity. In addition, the 

electricity sector is primarily 

domestic—little electricity is exported 

outside the U.S.—and there is low 

capacity for storage. In addition, the 

electricity sector is highly regulated, 

planned, and coordinated. As a result, 

holding demand constant, an increase in 

one type of generation will result in a 

decrease in another type of generation. 

Moreover, the higher-emitting 

generators, which are fossil fuel-fired, 

have higher variable costs than 

renewable generators, so that increased 

renewable generation will generally 

back out fossil fuel-fired generation. 

Because of these characteristics, the 

electricity sector has a long and wellestablished history of substituting one 

type of generation for another. This has 

occurred for a wide variety of reasons, 

many of which are directly related to 

the system’s primary purposes and 

functions, as well as for environmental 

reasons. As a result, at present, there is 

a well-established network of business 

and operational relationships and past 

practices that supports building blocks 

2 and 3. As noted elsewhere, a large 

segment of steam generators already 

have business relationships with 

existing NGCC units, and a large 

segment of all fossil fuel-fired EGUs 

already own, co-own, or have invested 

in RE. 

Many of these characteristics are 

unique to the utility power sector. 

Moreover, this complex of 

characteristics, ranging from the 

physical properties of electricity and the 

integrated nature of the grid to the 

institutional mechanisms that assure 

reliability and the existing practices and 

business relationships in the industry, 

combine to facilitate the 

implementation of building blocks 2 

and 3 in a uniquely efficient manner. 

This supports basing the emission limits 

on the ability of owners and operators 

of fossil fuel-fired EGUs to replace their 

generation with cleaner generation in 

other locations, sometimes owned by 

other entities. 

As noted above, commenters offered 

hypothetical examples to illustrate their 

concerns over precedential effects. Most 

of their concerns focused on building 

block 4, and most of their hypothetical 

examples concerned reductions in 

demand for various types of products. 

We address these concerns in the 

response to comments document, but 

we note here that, in any event, these 

concerns are mooted because we are not 

finalizing building block 4. Some 

commenters offered hypothetical 

examples for building blocks 2 and 3 as 

well. For example, some commenters 

asserted that the EPA could ‘‘develop 

standards of performance for tailpipe 

emissions from motor vehicles’’ by 

‘‘requiring car owners to shift some of 

their travel to buses,’’ which the 

commenters considered analogous to 

building block 2; or by ‘‘requiring there 

to be more electric vehicle purchases,’’ 

which the commenters considered 

analogous to building block 3.575

Commenters’ concerns over 

precedential impact cannot be taken to 

mean that the building blocks should 

not be considered to meet the 

requirements of the BSER or that the 

affected EGUs cannot be considered to 

meet the emission limits by 

implementing those measures. 

Moreover, because many of these 

individual characteristics, and their 

inherent complexity, are unique to the 

utility power sector, building blocks 2 

and 3 as applied to fossil fuel-fired 

EGUs will have a limited precedent for 

other industries and other types of 

rulemakings. For example, the 

commenter’s hypothetical examples 

noted above are inapposite for several 

reasons. The hypotheticals appear to be 

premised on government action 

mandating actions not implementable 

by emitting sources (e.g., that a 

government would ‘‘require[e] car 

owners to shift some of their travel to 

buses, or . . . require[e] there to be 

more electric vehicle purchases’’), 

whereas the measures in building blocks 

2 and 3 can be implemented by the 

affected EGUs. Nor have commenters 

attempted to address how car owners 

shifting travel to buses or purchasing 

more electric vehicles could be 

translated into lower tailpipe standards 

for motor vehicles.576

(d) ‘‘Best’’ in light of ‘‘cost . . . nonair 

quality health and environmental 

impact and energy requirements’’ and 

EPA’s past practice and current policy. 

The fourth constraint, or set of 

constraints, is that the system of 

emission reduction must be the ‘‘best,’’ 

‘‘taking into account the cost of 

achieving such reduction and any 

nonair quality health and environmental 

impact and energy requirements.’’ As 

noted, in light of the D.C. Circuit case 

law, the EPA has considered cost and 

energy factors on both an individual 

source basis and on the basis of the 

nationwide electricity sector. In 

determining what is ‘‘best,’’ the EPA has 

broad discretion to balance the 

enumerated factors.577 In interpreting 

and applying these provisions in this 

rulemaking to regulate CO2 emissions 

from affected EGUs under section 

111(d), we are acting consistently with 

our past practice for applying these 

provisions in previous section 111 

rulemakings and for regulating air 

pollutants from the electricity sector 

under other provisions of the CAA, as 

well as current policy. 

The great majority of our regulations 

under section 111 have been 111(b) 

regulations for new sources. As 

discussed in the Legal Memorandum 

and briefly below, the BSER identified 

under section 111(b) is designed to 

assure that affected sources are well 

controlled at the time of construction, 

and that approach is consistent with the 

design expressed in the legislative 

history for the 1970 CAA Amendments 

that enacted the provision. 

Traditionally, CAA section 111 

standards have been rate-based, 

allowing as much overall production of 

a particular good as is desired, provided 

that it is produced through an 

appropriately clean (or low-emitting) 

process. CAA section 111 performance 

standards have primarily targeted the 

means of production in an industry and 

not consumers’ demand for the product. 

Thus, the focus for the BSER has been 

on how to most cleanly produce a good, 

not on limiting how much of the good 

can be produced. 

One example of the focus under 

section 111 on clean production, not 

limitation of product is provided by the 

revised new source performance 

standards for electric utility steam 

generating units that we promulgated in 

1979 following the 1977 CAA 

Amendments to limit emissions of SO2, 

PM, and NOX. In relevant part, the 

revised standards limited SO2 emissions 

to 1.20 lb/million BTU heat input and 

imposed a 90 percent reduction in 

potential SO2 emissions. This was based 

on the application of flue gas 

desulfurization (FGD) together with coal 

preparation techniques. In the preamble, 

we explain that ‘‘[t]he intent of the final 

standards is to encourage power plant 

owners and operators to install the best 

available FGD systems and to 

implement effective operation and 

maintenance procedures but not to 

create power supply disruptions.’’ 578 579


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new steam-electric generating unit to another 

electric generating unit, there would be no net 

change in reserves within the power system. Thus, 

the emergency condition provisions prevent a failed 

FGD system from impacting upon the utility 

company’s ability to generate electric power and 

prevents an impact upon reserves needed by the 

power system to maintain reliable electric service.’’ 

Id. 

579The EPA’s 1982 revised new source 

performance standards for certain stationary gas 

turbines provide another example of a rulemaking 

that focused controls on reducing emissions, as well 

as reliance on the integrated grid to avoid power 

disruptions. 44 FR 33580 (June 11, 1979). In 

response to comments that requested a NOX

emission limit exemption for base load utility gas 

turbines, the EPA explained that ‘‘for utility 

turbines . . . since other electric generators on the 

grid can restore lost capacity caused by turbine 

down time’’ the NOX emission limit of 1150 ppm 

for such turbines would not be rescinded. 44 FR 

33580, at 33597–98. 

580See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12022 

(Mar. 1, 1977); ‘‘Standards of Performance for New 

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

581American Electric Power Co. v. Connecticut, 

131 S. Ct. 2527, 2539–40 (2011). 

582Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. 

Cir. 1981). Id. at 406 n. 526. 

583S. Rep. No. 91–1196, at 15–16 (Sept. 17, 1970), 

1970 CAA Legis. Hist. at 415–16 (explaining that 

the ‘‘[Administrator] should determine the 

achievable limits and let the owner or operator 

determine the most economic, acceptable technique 

to apply.’’). 

584H.R. Rep. No. 95–294, at 195 (May 12, 1977). 

585Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. 

Cir. 1981). 

586CAA section 101(b)(1). 

587CAA section 101(c). 

EPA has taken the same overall 

approach in its section 111(d) rules,580

including the CAMR rule noted below. 

Similarly, in a series of rulemakings 

regulating air pollutants from EGUs 

under several provisions of the CAA, we 

have focused our efforts on assuring that 

electricity is generated through cleaner 

or lower-emitting processes, and we 

have not sought to limit the aggregate 

amount of electricity that is generated. 

We describe those rules in section II, 

elsewhere in this section V.B.3., and in 

the Legal Memorandum. 

For example, as discussed in the Legal 

Memorandum, in the three transport 

rules promulgated under CAA section 

110(a)(2)(D)(i)(I)—the NOX SIP Call, 

CAIR, and CSAPR—which regulated 

precursors to ozone-smog and 

particulate matter, the EPA based 

certain aspects of the regulatory 

requirements on the fact that fossil fuelfired EGUs could shift generation to 

lower-emitting sources. In CAMR, the 

2005 rulemaking under section 111(d) 

regulating mercury emissions from coalfired EGUs, the EPA based the first 

phase of control requirements on the 

actions the affected EGUs were required 

to take under CAIR, including shifting 

generation to lower-emitting sources. In 

addition, as also discussed in the Legal 

Memorandum, in the EPA’s 2012 MATS 

rule regulating mercury from coal-fired 

EGUs under section 112, at industry’s 

urging, the EPA allowed compliance 

deadlines to be extended for coal-fired 

EGUs that desired to substitute 

replacement power of any type, 

including NGCC units or RE, for 

compliance purposes. 

While these and other rulemakings for 

fossil fuel-fired EGUs took different 

approaches towards lower-emitting 

generation and renewable generation, 

they all were based on control measures 

that reduced emissions without 

reducing aggregate levels of electricity 

generation. It should be noted that even 

though some of those rules established 

overall emission limits in the form of 

budgets implemented through a capand-trade program, the EPA recognized 

that the fossil fuel-fired EGUs that were 

subject to the rules could comply by 

shifting generation to lower-emitting 

EGUs, including relying on RE. In this 

manner, the rules limited emissions but 

on the basis that the industry could 

implement lower-emitting processes, 

and not based on reductions in overall 

generation. 

We are applying the same approach to 

this rulemaking. Our basis for this 

rulemaking is that affected EGUs can 

implement a system of emission 

reduction that will reduce the amount of 

their emissions without reducing overall 

electricity generation. This approach 

takes into account costs by minimizing 

economic disruption as well as the 

nation’s energy requirements by 

avoiding the need for environmentalbased reductions in the aggregate 

amount of electricity available to the 

consumer, commercial, and industrial 

sectors. 

This approach is a reasonable exercise 

of the EPA’s discretion under section 

111, consistent with the U.S. Supreme 

Court’s statements in its 2011 decision, 

American Electric Power Co. v. 

Connecticut, that the CAA and the EPA 

actions it authorizes displace any 

federal common law right to seek 

abatement of CO2 emissions from fossilfuel fired power plants. There, the Court 

emphasized that CAA section 111 

authorizes the EPA—which the Court 

identified as the ‘‘expert agency’’—to 

regulate CO2 emissions from fossil fuelfired power plants based an ‘‘informed 

assessment of competing interests . . . . 

Along with the environmental benefit 

potentially achievable, our Nation’s 

energy needs and the possibility of 

economic disruption must weigh in the 

balance.’’ 581

Similarly, the D.C. Circuit, in a 1981 

decision upholding the EPA’s section 

111(b) standards for air pollutants from 

fossil fuel-fired EGUs, stated that 

section 111 regulations concerning the 

electric power sector ‘‘demand a careful 

weighing of cost, environmental, and 

energy considerations.’’ 582 This exercise 

of policy discretion is consistent with 

Congress’s expectation that the 

Administrator ‘‘should determine the 

achievable limits’’ 583 and ‘‘would 

establish guidelines as to what the best 

system for each such category of 

existing sources is.’’ 584 As the D.C. 

Circuit explained, ‘‘[i]t seems likely that 

if Congress meant . . . to curtail EPA’s 

discretion to weigh various policy 

considerations it would have explicitly 

said so in section 111, as it did in other 

parts of the statute.’’ 585

Our interpretation that CAA section 

111 targets supply-side activities that 

allow continued production of a 

product through use of a cleaner 

process, rather than targeting consumeroriented behavior, also furthers 

Congress’ intent of promoting cleaner 

production measures ‘‘to protect and 

enhance the quality of the Nation’s air 

resources so as to promote the public 

health and welfare and the productive 

capacity of its population.’’ 586 This 

principle is also consistent with 

promoting ‘‘reasonable . . . 

governmental actions . . . for pollution 

prevention.’’ 587

In this rule, we are applying that same 

approach in interpreting the BSER 

provisions of section 111. That is, we 

are basing the regulatory requirements 

on measures the affected EGUs can 

implement to assure that electricity is 

generated with lower emissions, taking 

into account the integrated nature of the 

industry and current industry practices. 

Building blocks 1, 2 and 3 fall squarely 

within this paradigm; they do not 

require reductions in the total amount of 

electricity produced. 

We recognize that commenters have 

raised extensive legal concerns about 

building block 4. We recognize that 

building block 4 is different from 

building blocks 1, 2, and 3 and the 

pollution control measures that we have 

considered under CAA section 111. 

Accordingly, under our interpretation of 

section 111, informed by our past 

practice and current policy, today’s final 

action excludes building block 4 from 

the BSER. Building block 4 is outside 

our paradigm for section 111 as it targets 


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588See Util. Air Reg. Group v. EPA, 134 S. Ct. 

2427, 2436 (2014). 

589As discussed below, however, reduced 

generation remains important to this rule in that it 

is one of the methods for implementing the building 

blocks. 

consumer-oriented behavior and 

demand for the good, which would 

reduce the amount of electricity to be 

produced. 

Although numerous commenters 

urged us to include demand-side EE 

measures as part of the BSER, as we had 

proposed to do, we conclude that we 

cannot do so under our historical 

practice, current policy, and current 

approach to interpreting section 111 as 

well as our historical practice in 

regulating the electricity sector under 

other CAA provisions. While building 

blocks 2 and 3 are rooted in our past 

practice and policy, building block 4 is 

not and would require a change (which 

we are not making) in our interpretation 

and implementation and application of 

CAA section 111. 

Excluding demand-side EE measures 

from the BSER has the benefit of 

allaying legal and other concerns raised 

by commenters, including concerns that 

individuals could be ‘‘swept into’’ the 

regulatory process by imposing 

requirements on ‘‘every household in 

the land.’’ 588 While building block 4 

could have been implemented without 

imposing requirements on individual 

households, this final rule resolves any 

doubt on this matter and is not based on 

the inclusion of demand-side EE as part 

of the BSER. 

By the same token, we are not 

finalizing reduced generation of 

electricity overall as the BSER. Instead, 

components of the BSER focus on 

shifting generation to lower- or zeroemitting processes for producing 

electricity.589

(e) Constraints for new sources. 

For new sources, practical and policy 

concerns support the interpretation of 

basing the BSER on controls that new 

sources can install at the time of 

construction, so that they will be wellcontrolled throughout their long useful 

lives. This approach is consistent with 

the legislative history. We discuss this 

at greater length in the Legal 

Memorandum. 

4. Relationship Between a Source’s 

Implementation of Building Blocks 2 

and 3 and Its Emissions 

In this section, we discuss the 

relationship between an affected EGU’s 

implementation of the measures in 

building blocks 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 zeroemitting generation and may apply 

credits from that generation against its 

emission rate. Those credits reduce the 

affected EGU’s emission rate and 

thereby help it to achieve its emission 

limit. 

In addition, the additional low- or 

zero-emitting generation that results 

from the affected EGU’s investment will 

generally displace higher-emitting 

generation. This is because, as described 

above, higher-emitting generation 

generally has higher variable costs, 

reflecting its fuel costs, than, at least, 

zero-emitting generation. Displacement 

of higher-emitting generation will lower 

overall CO2 emissions from the source 

category of affected EGUs. 

If an affected EGU implements 

building block 2 or 3 by reducing its 

own generation, it will reduce its own 

emissions. However, the affected EGU 

may also or alternatively choose to 

implement building block 2 or 3 by 

investing in lower- or zero-emitting 

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 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 expect that 

many states will carry out their 

obligations under this rule by imposing 

standards of performance that 

incorporate trading or other multi-entity 

generation-replacement strategies. 

Indeed, any emission rate-based 

standard may not necessarily result in 

emission reductions from any particular 

affected source (or even all of the 

affected sources in the category) as a 

result of the ability of the particular 

source (or even all of them) to increase 

its production and, therefore, its 

emissions, even while maintaining the 

required emission rate. 

5. Reduced Generation and 

Implementation of the BSER 

In the proposed rulemaking, we 

described the BSER as the measures 

included in building block 1 as well the 

set of measures included in building 

blocks 2, 3 and 4 or, in the alternative, 

reduced generation or utilization by the 

affected EGUs in the amount of building 

blocks 2, 3 and 4. In this final rule, 

based on the comments and further 

evaluation, we are refining our approach 

to the BSER. Specifically, we are 

determining the BSER as the 

combination of measures included in 

building blocks 1, 2, and 3.Building 

blocks 2 and 3 entail substitution of 

lower-emitting generation for higheremitting generation, which ensures that 

aggregate production levels can 

continue to meet demand even where an 

individual affected EGU decreases its 


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590An 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. 

591CAA section 169A(g)(2). 

592 40 CFR 51.301. 

own output to reduce emissions. The 

amount of generation from the increased 

utilization of existing NGCC units 

determines a portion of the amount of 

reduced generation that affected fossil 

fuel-fired steam EGUs could undertake 

to achieve building block 2, and the 

amount of generation from the use of 

expanded lower- or zero-emitting 

generating capacity that could be 

provided, determines a portion of the 

amount of reduced generation that 

affected fossil fuel-fired steam EGUs, as 

well as the entire amount of reduced 

generation that affected NGCC units 

could undertake to implement building 

blocks 2 and 3. This section discusses 

the reasons that reduced generation is 

one of the set of reasonable and wellestablished actions that an affected EGU 

can implement to achieve its emission 

limits. We are not finalizing our 

proposal that reduced overall generation 

of electricity may by itself be considered 

the BSER, for the reason that reduced 

generation by itself does not fit within 

our historical and current interpretation 

of the BSER. Specifically, reduced 

generation by itself is about changing 

the amount of product produced rather 

than producing the same product with 

a process that has fewer emissions. 

a. Background. As noted, for both 

rate-based and mass-based state plans, 

affected EGUs may take a set of actions 

to comply with their emission 

standards. An affected EGU may comply 

with an emission rate-based standard 

(e.g., a limit on the amount of CO2 per 

MWh) by acquiring, through one means 

or another, credits from lower- or zeroemitting generation (building blocks 2 

or 3) to reduce its emission rate for 

compliance purposes. In addition, the 

affected EGU may reduce its generation, 

and if it does so, it then needs to acquire 

fewer of those credits to meet its 

emission rate.590 Under these 

circumstances, the affected EGU would 

in effect replace part of its higheremitting generation with lower- or zeroemitting generation. On the other hand, 

an affected EGU that is subject to a 

mass-based standard—for example, a 

requirement to hold enough allowances 

to cover its emissions (e.g., one 

allowance for each ton of emissions in 

any year)—may comply at least in part 

by reducing its generation and, thus, its 

emissions. Therefore, one type of action 

that an affected EGU may take to 

achieve either of these emission limits 

is to reduce its generation. Further, 

reduced generation by individual 

sources offers a pathway to compliance 

in and of itself. That is, a state may 

adopt a mass-based goal, assign massbased standards to its sources, and those 

sources may comply with their massbased 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 well-established method 

for individual fossil fuel-fired power 

plants to comply with their emission 

limits. 

Reduced generation in the amounts 

contemplated in this rule, as undertaken 

by individual sources to achieve their 

emission limits, reduces emissions from 

the affected sources, but because of the 

integrated and interconnected nature of 

the power sector, can be accommodated 

without significant cost or disruption. 

The electric transmission grid 

interconnects the nation’s generation 

resources over large regions. Electric 

system operators coordinate, control, 

and monitor the electric transmission 

grid to ensure cost-effective and reliable 

delivery of power. These system 

operators continuously balance 

electricity supply and demand, ensuring 

that needed generation and/or demand 

resources are available to meet 

electricity demand. Diverse resources 

generate electricity that is transmitted 

and distributed through a complex 

system of interconnected components to 

end-use consumers. 

The electricity system was designed 

to meet these core functions. The three 

components of the electricity supply 

system—generation, transmission and 

distribution—coordinate to deliver 

electricity from the point of generation 

to the point of consumption. This 

interconnectedness is a fundamental 

aspect of the nation’s electricity system, 

requiring a complicated integration of 

all components of the system to balance 

supply and demand and a federal, state 

and local regulatory network to oversee 

the physically interconnected network. 

Electricity from a diverse set of 

generation resources such as natural gas, 

nuclear, coal and renewables is 

distributed over high-voltage 

transmission lines. The system is 

planned and operated to ensure that 

there are adequate resources to meet 

electricity demand plus additional 

available capacity over and above the 

capacity needed to meet normal peak 

demand levels. System operators have a 

number of resources potentially 

available to meet electricity demand, 

including electricity generated by 

electric generation units of various types 

as well as demand-side resources. 

Importantly, if generation is reduced 

from one generator, safeguards are in 

place to ensure that adequate supply is 

still available to meet demand. We 

describe these safeguards in the 

background section of this preamble. 

Both Congress and the EPA have 

recognized reduced generation as one of 

the measures that fossil fuel-fired EGUs 

may implement to reduce their 

emissions of air pollutants and thereby 

achieve emission limits. Congress, in 

enacting the allowance requirements in 

CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for 

each ton of SO2 emitted, explicitly 

recognized that fossil fuel-fired EGUs 

could meet this requirement by 

reducing their generation. In fact, 

Congress anticipated that fossil fuelfired 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.’’ 

The EPA has also recognized in 

several rulemakings limiting emissions 

from fossil fuel-fired EGUs that reduced 

generation is one of the methods of 

emission reduction that an EGU was 

expected to rely on to achieve its 

emission limitations. Examples include 

rulemakings to impose requirements 

that sources implement BART to reduce 

their emissions of air pollutants that 

cause or contribute to visibility 

impairment. As explained earlier, for 

certain older stationary sources that 

cause or contribute to visibility 

impairment, including fossil fuel-fired 

EGUs, states must determine BART on 

the basis of five statutory factors, such 

as costs and energy and non-air quality 

impacts.591 In 1980, the EPA 

promulgated a regulatory definition of 

BART: ‘‘an emission limitation based on 

the degree of reduction achievable 

through the best system of continuous 

emission reduction for each pollutant 

which is emitted by an existing 

stationary facility.’’ 592 Both the 

statutory factors and the regulatory 

definition resemble the definition of the 

BSER under CAA section 111(a)(1) 


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593 77 FR 24794, 24810 (Apr. 25, 2012). 

594See, 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). 

595See, 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). 

596 40 CFR 52.21(b)(4) (emphasis added). 

597 John Seitz, Director, Office of Air Quality 

Planning and Standards, and Robert Van Heuvelen, 

Director, Office of Regulatory Enforcement, Release 

of Interim Policy on Federal Enforceability of 

Limitations on Potential to Emit, at 3 (Jan. 22, 1996), 

available at http://www.epa.gov/region07/air/nsr/

nsrmemos/pottoemi.pdf. 

598See 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). 

599See, e.g., 40 CFR 52.21(b)(4). 

600See 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.’’). 

601See 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.’’). 

(although, as noted, the statutory 

definition of BART is more technology 

focused than the definition of BSER). In 

its regional haze SIP, the State of New 

York determined that BART for the NOX

emissions from two coal-fired boilers 

that served as peaking units was caps on 

baseline emissions rates and annual 

capacity factors of 5 percent and 10 

percent, respectively.593

There have been numerous other 

instances in which fossil fuel-fired 

EGUs have reduced their individual 

generation, or placed limits on their 

generation, in order to achieve, or 

obviate, emission standards. In fact, 

there are numerous examples of EGUs 

that take restrictions on hours of 

operation in their permits for the 

purpose of avoiding CAA obligations, 

including avoiding triggering the 

requirements of the Prevention of 

Significant Deterioration (PSD), 

Nonattainment New Source Review 

(NNSR), or Title V programs (including 

Title V fees), and avoiding triggering 

HAP requirements. Such restrictions 

may also be taken to limit emissions of 

pollutants, such as limiting emissions of 

criteria pollutants for attainment 

purposes. 

More specifically, EPA’s regulations 

for a number of air programs expressly 

recognize that certain sources may take 

enforceable limits on hours of operation 

in order to avoid triggering CAA 

obligations that would otherwise apply 

to the source. Stationary sources that 

emit or have the potential to emit a 

pollutant at a level that is equal to or 

greater than specified thresholds are 

subject to major source requirements.594

A source may voluntarily obtain a 

synthetic minor limitation—that is, a 

legally and practicably enforceable 

restriction that has the effect of limiting 

emissions below the relevant level—to 

avoid triggering a major stationary 

source requirement.595 Such synthetic 

minor limits may be based on 

restrictions on the hours of operation, as 

provided in EPA’s regulations defining 

‘‘potential to emit,’’ as well as on air 

pollution control equipment. ‘‘Potential 

to emit’’ is defined, for instance, in the 

regulations for the PSD program for 

permits issued under federal authority 

as: ‘‘the maximum capacity of a 

stationary source to emit a pollutant 

under its physical and operational 

design. Any physical or operational 

limitation on the capacity of the source 

to emit a pollutant, including air 

pollution control equipment and 

restrictions on hours of operation . . . 

shall be treated as part of its design if 

the limitation or the effect it would have 

on emissions is federally 

enforceable,’’ 596 or ‘‘legally and 

practicably enforceable by a state or 

local air pollution control agency.’’ 597

The regulations for other air programs 

similarly recognize that potential to 

emit may be limited through restrictions 

on hours of operations in their 

corresponding definitions of ‘‘potential 

to emit.’’ 598 These regulatory provisions 

make clear that restrictions on potential 

to emit include both ‘‘air pollution 

control equipment’’ and ‘‘restrictions on 

hours of operation,’’ and indicate that 

these are equally cognizable means of 

restricting emissions to comply with, or 

avoid, CAA requirements.599

As one of many examples of a fossilfuel 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 simplecycle 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, NOX and SO2 below 

the PSD threshold of 250 tpy.600 As 

another example, Sunbury Generation 

LP in Pennsylvania obtained a minor 

new source preconstruction permit, 

called a plan approval, for a repowering 

project from the Pennsylvania 

Department of Environmental Protection 

in 2013 that limited the hours of 

operation of three combined cycle 

combustion turbines that were planned 

for construction in order to remain 

below the significance threshold for 

GHGs.601 The Legal Memorandum 

includes numerous other examples of 

power plants accepting permit limits 

that reduce generation to meet, or avoid 

the need to meet, emission limits. 

There are several ways that an 

affected EGU may implement reduced 

generation. For example, an EGU may 

accept a permit requirement that 

specifically limits its operating hours. In 

addition, an EGU may treat the cost of 

its generation as including an additional 

amount associated with environmental 

impacts, which requires it to raise its 

bid price, so that the EGU is dispatched 

less. 

c. Other aspects of reduced 

generation. 

The amounts of increased existing 

NGCC generation and new renewables, 

in the amounts reflected in building 

blocks 2 and 3, can be substituted for 

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 


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602Although, as discussed in the text in this 

section of the preamble, we are not treating reduced 

overall generation of electricity as the BSER 

(because it does not meet our historical and current 

approach of defining the BSER to include methods 

that allow the same amount of production but with 

a lower-emitting process) we note that reduced 

generation by individual higher-emitting EGUs to 

implement building blocks 2 and 3 meets the 

following criteria for the BSER: As the examples in 

the text and in the Legal Memorandum make clear, 

reduced generation is ‘‘adequately demonstrated’’ 

as a method of reducing emissions (because 

Congress and the EPA have recognized it and on 

numerous occasions, power plants have relied on 

it); it is of reasonable cost; it does not have adverse 

effects on energy requirements at the level of the 

individual affected source (because it does not 

require additional energy usage by the source) or 

the source category or the U.S.; and it does not 

create adverse environmental problems. 

603EEI comment, at 284. 

604 Indeed, load shifting—as substitute generation 

is sometimes called—is an ‘‘easy and fairly 

inexpensive strategy’’ that ‘‘may be used in 

conjunction with other control measures’’ for 

‘‘emission reduction.’’ Donald S. Shepard, ‘‘A Load 

Shifting Model for Air Pollution Control in the 

Electric Power Industry,’’ Journal of the Air 

Pollution Control Association, Vol. 20, No. 11, p. 

760 (Nov. 1970). In fact, load shifting has been 

recognized as a pollution control technique as early 

as 1968, when it was included in the ‘‘Chicago Air 

Pollution System Model’’ for controlling incidents 

of extremely high pollution. E.J. Croke, et al., 

‘‘Chicago Air Pollution System Model, Third 

Quarterly Progress Report,’’ Chicago Department of 

Air Pollution Control, p. 186 (1968) (discussing the 

feasibility of ‘‘Control by Load Reduction’’ in 

combination with load shifting as applied to the 

Commonwealth Edison Company), available at 

http://www.osti.gov/scitech/servlets/purl/4827809. 

The report also considered ‘‘combining fuel 

switching and load reduction’’ as a possible air 

pollution abatement technique. See id. at 188. The 

report recognized, as an initial matter, that the 

Commonwealth Edison Company (CECO) was 

‘‘constrained to meet the total load demand’’ but 

that ‘‘load reduction at one plant or even a number 

of plants is usually feasible by shifting the power 

demand to other plants in the system.’’ Id. As a 

result, the report noted, ‘‘load shifting within the 

physical limits of the CECO system . . . may be a 

highly desirable control mechanism.’’ Id. The report 

also predicted that ‘‘[i]n the future, it may be 

possible to form reciprocal agreements to obtain 

‘pollution abatement’ power from neighbor 

companies during a pollution incident and return 

this borrowed power at some later date.’’ Id. at 187. 

605The 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. 

choose to reduce their CO2 emissions by 

means of reducing their generation. 

Reduced generation by affected EGUs, 

in the amounts that affected EGUs may 

rely on to implement the selected 

building blocks, will not have adverse 

effects on the utility power sector and 

will not reduce overall electricity 

generation. In light of the emission 

limits of this rule, because of the 

availability of the measures in building 

blocks 2 and 3, and because the grid is 

interconnected and the electricity 

system is highly planned, reductions in 

generation by fossil fuel-fired EGUs in 

the amount contemplated if they were to 

implement the building blocks, and 

occurring over the lengthy time frames 

provided under this rule, will result in 

replacement generation that generally is 

lower- or zero-emitting. Mechanisms are 

in place in both regulated and 

deregulated electricity markets to assure 

that substitute generation will become 

available and/or steps to reduce demand 

will be taken to compensate for reduced 

generation by affected EGUs. As a result, 

reduced generation will not give rise to 

reliability concerns or have other 

adverse effects on the utility power 

sector and are of reasonable cost for the 

affected source category and the 

nationwide electricity system.602 All 

these results come about because the 

operation of the electrical grid through 

integrated generation, transmission, and 

distribution networks creates 

substitutability for electricity and 

electricity services, which allows 

decreases in generation at affected fossil 

fuel-fired steam EGUs to be replaced by 

increases in generation at affected NGCC 

units (building block 2) and allows 

decreases in generation at all affected 

EGUs to be replaced by increased 

generation at new lower- and zeroemitting 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. 

d. Comments concerning limiting 

principles. 

A commenter stated that ‘‘an 

interpretation of [‘system of emission 

reduction’] that relies primarily on 

reduced utilization has no clear limiting 

principle.’’ 603 We disagree with this 

concern, for the following reasons. 

As discussed, in this final rule, we are 

identifying the BSER as the combination 

of the three building blocks. Building 

blocks 2 and 3 entail substitution of 

lower- or zero-emitting generation for 

higher-emitting generation, and one 

component of that substitution is 

reduced generation, which is limited in 

several respects discussed below. 

Accordingly, our identification of the 

BSER in this final rule does not ‘‘rel[y] 

primarily’’ on reduced utilization in and 

of itself (and therefore reduced 

generation of the product overall, 

electricity) as the BSER. Rather, the 

BSER is, in addition to building block 

1, the substitution of lower- or zeroemitting 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.604 The commenter’s 

concerns over a perceived lack of a 

limiting principle cannot be taken to 

mean that reduced generation by higheremitting EGUs cannot be considered to 

be a method for affected EGUs to 

achieve their emission limits. 

Moreover, reduced generation, as 

applied to affected EGUs in this rule, is 

limited in a number of respects. The 

amount of reduced generation is the 

amount of replacement generation that 

is lower- or zero-emitting, that is of 

reasonable cost, that can be generated 

without jeopardizing reliability, and 

that meets the other requirements for 

the BSER. As discussed, that amount is 

the amount of generation in building 

blocks 2 and 3.605

Finally, as discussed, the integrated 

nature of the electricity system, coupled 

with the high substitutability of 

electricity, allows EGUs to reduce their 

generation without adversely affecting 

the availability of their product. Those 

characteristics facilitate replacement of 

generation that has been reduced, and 

for that reason, EGUs have a long 

history of reducing their generation and 

either replacing it directly or having it 

replaced through the operation of the 

interconnected electricity system 

through measures similar to those in 

building blocks 2 and 3. Thus, an EGU 

can either directly replace its 

generation, or simply reduce its 

generation, and in the latter case, the 

integrated grid, combined with the high 

degree of planning and various 

reliability safeguards, will result in 

entities providing replacement 

generation. This means that consumers 

receive exactly the same amount of the 

same product, electricity, after the 

reduced generation that they received 

before it. No other industry is both 

physically interconnected in this 

manner and manufactures such a highly 

substitutable product; as a result, the 

use of reduced generation is not easily 

transferrable to another industry. 

6. Reasons That This Rule Is Within the 

EPA’s Statutory Authority and Does Not 

Represent Over-Reaching 

In this section, we respond to adverse 

comments that the EPA is overreaching 

in this rulemaking by attempting to 

direct the energy sector. These 

commenters construed the proposed 

rulemaking as the EPA proposing to 

mandate the implementation of the 

measures in the building blocks, 


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606 134 S. Ct. 2427 (2014). 

607Utility Air Regulatory Group v. EPA, 134 S. Ct. 

2427, 2444 (2014) (citations omitted). 

608 In fact, the EPA is expressly precluded from 

mandating specific controls except in certain 

limited circumstances. See 42 U.S.C. 7411(b)(5). For 

instance, the EPA is authorized to mandate a 

particular ‘‘design, equipment, work practice, or 

operational standard, or combination thereof,’’ 

when it is ‘‘not feasible to prescribe or enforce a 

standard of performance’’ for new sources. 42 

U.S.C. 7411(h)(1). CAA section 111(h) also 

highlights for us that while ‘‘design, equipment, 

work practice, or operational standards’’ may be 

directly mandated by the EPA, CAA section 

111(a)(1) encompasses a broader suite of measures 

for consideration as the BSER. 

609NACAA, ‘‘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, nonpartisan, non-profit association of air pollution 

control agencies in 41 states, the District of 

Columbia, four territories and 116 metropolitan 

areas.’’ Id. 

610Martinson, Erica, ‘‘Cap and trade lives on 

through the states,’’ Politico (May 27, 2014), 

http://www.politico.com/story/2014/05/cap-andtrade-states-107135.html. 

611A state may regulate non-EGUs as part of a 

state measures approach, but those measures would 

not be federally enforceable. 

including investment in RE and 

implementation of a broad range of state 

and utility demand-side EE programs. 

Commenters added that in some 

instances, the affected EGUs and states 

would have no choice but to take the 

actions in the building blocks because 

they would not otherwise be able to 

achieve their emission standards. 

Commenters also emphasized that with 

the proposed portfolio approach, the 

rule would impose federally enforceable 

requirements on a wide range of entities 

that do not emit CO2 and have not 

previously been subject to CAA 

regulation. Commenters cite the U.S. 

Supreme Court’s statements in Utility 

Air Regulatory Group v. EPA (UARG) 606

that caution an agency against 

interpreting its statutory authority in a 

way that ‘‘would bring about an 

enormous and transformative expansion 

in [its] regulatory authority without 

clear congressional authorization,’’ and 

that add, ‘‘When an agency claims to 

discover in a long-extant statute an 

unheralded power to regulate ‘a 

significant portion of the American 

economy,’ . . . we typically greet its 

announcement with a measure of 

skepticism.’’ 607 Commenters assert that 

in this rule, the EPA is taking the 

actions that the UARG opinion 

cautioned against. For the reasons 

discussed below, these comments are 

incorrect and misunderstand 

fundamental aspects of this rule. In 

addition, to the extent these comments 

address either building block 4 or the 

portfolio approach they are moot, 

because the EPA is not finalizing those 

elements of the proposal. 

In this rule, the EPA is following the 

same approach that it uses in any 

rulemaking under CAA section 111(d), 

which is designed to regulate the air 

pollutants from the source category at 

issue. First, the EPA identifies the BSER 

to reduce harmful air pollution. Second, 

based on the BSER, the EPA 

promulgates emission guidelines, which 

generally take the form of emission rates 

applicable to the affected sources. In 

this case, the EPA is promulgating a 

uniform CO2 emission performance rate 

for steam-generating EGUs and a 

uniform CO2 emission performance rate 

for combustion turbines, and the EPA is 

translating those rates into a combined 

emission rate and equivalent mass limit 

for each state. These emission 

guidelines serve as the guideposts for 

state plan requirements. The states, in 

turn, promulgate standards of 

performance and, in doing so, retain 

significant flexibility either to 

promulgate rate-based emission 

standards that mirror the emission 

performance rates in the guidelines, 

promulgate rate-based emission 

standards that are equivalent to the 

emission performance rates in the 

guidelines, or promulgate equivalent 

mass-based emission standards. The 

sources, in turn, are required to comply 

with their emission standards, and may 

do so through any means they choose. 

Alternatively, the state may adopt the 

state-measures approach, which 

provides additional flexibility. 

Thus, the EPA is not requiring that 

the affected EGUs take any particular 

action, such as implementation of the 

building blocks. Rather, as just 

explained, the EPA is regulating the 

affected EGUs’ emissions by requiring 

that the state submit state plans that 

achieve specified emission performance 

levels. The states may choose from a 

wide range of emission limits to impose 

on their sources, and the sources may 

choose from a wide range of compliance 

options to achieve their emission limits. 

Those options include various means of 

implementing the building blocks as 

well as numerous other compliance 

options, ranging from—depending in 

part on whether the state imposes a ratebased or mass-based emission limit— 

implementation of demand-side EE 

measures to natural gas co-firing.608

As some indication of the diverse set 

of actions we expect to comply with the 

requirements of this rule, we note that 

demand-side EE programs, in particular, 

are expected to be a significant 

compliance method, in light of their low 

costs. In addition, the National 

Association of Clean Air Agencies 

(NACAA) has issued a report that 

provides a detailed discussion of 25 

approaches to CO2 reduction in the 

electricity sector.609 In addition, we 

note that the nine RGGI states— 

Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New 

Hampshire, New York, Rhode Island 

and Vermont—have indicated that they 

intend to maintain their current state 

programs, which this rule would allow, 

and there are reports that other states 

may seek to join RGGI.610 Similarly, 

California has indicated that it intends 

to maintain its current state program, 

which this rule would allow. Other 

states could employ the types of 

methods used in Oregon, Washington, 

Colorado, or Minnesota, described in 

the background section of this preamble. 

As a practical matter, we expect that 

for some affected EGUs, implementation 

of the building blocks will be the most 

attractive option for compliance. This 

does not mean, contrary to the adverse 

comments noted above, that this rule 

constitutes a redesign of the energy 

sector. As discussed above, the building 

blocks meet the criteria to be part of the 

best system of emission reduction . . . 

adequately demonstrated. The fact that 

some sources will implement the 

building blocks and that this may result 

in changes in the electricity sector does 

not mean that the building blocks 

cannot be considered the BSER under 

CAA section 111(d). 

In this rule, as with all CAA section 

111(d) rules, the EPA is not directly 

regulating any entities. Moreover, the 

EPA is not finalizing the proposed 

portfolio approach. Accordingly, the 

EPA is neither requiring nor authorizing 

the states to regulate non-affected EGUs 

in their CAA section 111(d) plans.611

Moreover, contrary to adverse 

comments, this rule does not require the 

states to adopt a particular type of 

energy policy or implement particulate 

types of energy measures. Under this 

rule, a state may comply with its 

obligations by adopting the emission 

standards approach to its state plan and 

imposing rate-based or mass-based 

emission standards on its affected EGUs. 

In this manner, this rule is consistent 

with prior section 111(d) rulemaking 

actions, in which the states have 

complied by promulgating one or both 

of those types of standards of 

performance. In this rulemaking, as an 

alternative, the state may adopt the state 

measures approach, under which the 

state could, if it wishes, adopt particular 

types of energy measures that would 

lead to reductions in emissions from its 

EGUs. But again, this rule does not 

require the state to implement a 


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612The D.C. Circuit acknowledged this legislative 

history in Sierra Club v. EPA, 657 F.2d 298, 331 

(D.C. Cir. 1981). There, the Court stated: 

[T]he Reports from both Houses on the Senate 

and House bills illustrate very clearly that Congress 

itself was using a long-term lens with a broad focus 

on future costs, environmental and energy effects of 

different technological systems when it discussed 

section 111. [Citing S. Rep. No. 95–127, 95th Cong., 

1st Sess. (1977), 3 Legis. Hist. 1371; H.R. Rep. No. 

95–294, 95th Cong., 1st Sess. 188 (1977), 4 Legis. 

Hist. 2465.] 

613American Electric Power Co. v. Connecticut, 

131 S. Ct. 2527, 2539–40 (2011). 

614Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. 

Cir. 1981). 

615Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. 

Cir. 1981). The Court supported this statement with 

a lengthy quotation from a scholarly article, which 

stated, in part: 

Consider for a moment the chain of collective 

decisions and their effects just in the case of electric 

utilities. Petroleum imports can be conserved by 

switching from oil-fired to coal-fired generation. 

But barring other measures, burning high-sulfur 

Eastern coal substantially increases pollution. 

Sulfur can be ‘‘scrubbed’’ from coal smoke in the 

stack, but at a heavy cost, with devices that turn out 

huge volumes of sulfur wastes that must be 

disposed of and about whose reliability there is 

some question. Intermittent control techniques 

(installing high smokestacks and switching off 

burners when meteorological conditions are 

adverse) can, at lower cost, reduce local 

concentrations of sulfur oxides in the air, but 

cannot cope with the growing problem of sulfates 

and widespread acid rainfall. Use of low-sulfur 

Western coal would avoid many of these problems, 

but this coal is obtained by strip mining. Stripmining 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. 

616For 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. 

particular type of energy policy or adopt 

particular types of energy measures. 

It is certainly reasonable to expect 

that compliance with these air pollution 

controls will have costs, and those costs 

will affect the electricity sector by 

discouraging generation of fossil fuelfired electricity and encouraging less 

costly alternative means of generating 

electricity or reducing demand. But for 

affected EGUs, air pollution controls 

necessarily entail costs that affect the 

electricity sector and, in fact, the entire 

nation, regardless of what BSER the EPA 

identifies as the basis for the controls. 

For example, had some type of add-on 

control such as CCS been identified as 

the BSER for coal-fired EGUs, sources 

that complied by installing that control 

would incur higher costs. As a result, 

generation from coal-fired EGUs would 

be expected to decrease and be replaced 

at least in part by generation from 

existing NGCC units and new 

renewables because those forms of 

generation would see their competitive 

positions improved. 

This basic fact that EPA regulation of 

air pollutants from affected EGUs 

invariably affects the utility sector is 

well-recognized and in no way indicates 

that such regulation exceed the EPA’s 

authority. In revising CAA section 111 

in the 1977 CAA Amendments, 

Congress explicitly acknowledged that 

the EPA’s rules under CAA section 111 

for EGUs would significantly impact the 

energy sector.612 The Courts have 

recognized that, too. The U.S. Supreme 

Court, in its 2011 decision that the CAA 

and the EPA actions it authorizes 

displace any federal common law right 

to seek abatement of CO2 emissions 

from fossil fuel-fired power plants, 

emphasized that CAA section 111 

authorizes the EPA—which the Court 

identified as the ‘‘expert agency’’—to 

regulate CO2 emissions from these 

sources in a manner that balances ‘‘our 

Nation’s energy needs and the 

possibility of economic disruption:’’ 

The appropriate amount of regulation in 

any particular greenhouse gas-producing 

sector cannot be prescribed in a vacuum: As 

with other questions of national or 

international policy, informed assessment of 

competing interests is required. Along with 

the environmental benefit potentially 

achievable, our Nation’s energy needs and 

the possibility of economic disruption must 

weigh in the balance. 

The [CAA] entrusts such complex 

balancing to EPA in the first instance, in 

combination with state regulators. Each 

‘‘standard of performance’’ EPA sets must 

‘‘tak[e] into account the cost of achieving 

[emissions] reduction and any nonair quality 

health and environmental impact and energy 

requirements.’’ § 7411(a)(1), (b)(1)(B), (d)(1); 

see also 40 CFR 60.24(f) (EPA may permit 

state plans to deviate from generally 

applicable emissions standards upon 

demonstration that costs are ‘‘[u]nreasonable’’). EPA may ‘‘distinguish among 

classes, types, and sizes’’ of stationary 

sources in apportioning responsibility for 

emissions reductions. § 7411(b)(2), (d); see 

also 40 CFR 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, 

case-by-case injunctions.613

Similarly, the D.C. Circuit, in its 1981 

decision upholding the EPA’s rules to 

reduce SO2 emissions from new coalfired EGUs under the version of CAA 

section 111(b) adopted in the 1977 CAA 

Amendments, stated: 

[S]ection 111 most reasonably seems to 

require that EPA identify the emission levels 

that are ‘‘achievable’’ with ‘‘adequately 

demonstrated technology.’’ After EPA makes 

this determination, it must exercise its 

discretion to choose an achievable emission 

level which represents the best balance of 

economic, environmental, and energy 

considerations. It follows that to exercise this 

discretion EPA must examine the effects of 

technology on the grand scale in order to 

decide which level of control is best. . . . 

The standard is, after all, a national standard 

with long-term effects.614

The D.C. Circuit added: ‘‘Regulations 

such as those involved here demand a 

careful weighing of cost, environmental, 

and energy considerations. They also 

have broad implications for national 

economic policy.’’ 615 This rule has 

‘‘economic, environmental, and 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 co-firing with natural gas), and 

add-on controls (for CO2 emissions, that 

entails CCS). However, it became 

apparent that even if the EPA could 

have finalized those controls as the 

BSER616 and established the same 

uniform CO2 emission performance 

rates, the affected EGUs would rely on 

less expensive ways to achieve their 

emission limits. Specifically, instead of 

relying on co-firing and CCS, the 

affected EGUs generally would replace 

their generation with lower- or zeroemitting 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 zeroemitting sources (or, as proposed, 

demand-side EE), they request that 

those measures be available for 

compliance, which indicates their 


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617See 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.’’). 

618Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 

2443 (2014). 

619States may regulate non-affected EGUs 

through a state measures approach, but those 

regulations would not be federally enforceable. 

620ACC et al. (Associations) comments at 40, 

Luminant comments at 89. 

interest in implementing those 

measures.617

We expect that many sources will 

choose to comply with their emission 

limits through the measures in building 

blocks 2 and 3, but contrary to the 

assertions of some commenters, this will 

not result in unprecedented and 

fundamental alterations to the energy 

sector. As discussed above, Congress 

relied on the same measures as those the 

EPA is including in building blocks 2 

and 3 as essential parts of the basis for 

the Title IV emission limits for fossil 

fuel-fired EGUs, and the EPA did the 

same for the emission limits in various 

rules for those same sources. 

In addition, reliance on the measures 

in building blocks 2 and 3 is fully 

consistent with the recent changes and 

current trends in electricity generation, 

and as a result, would by no means 

entail fundamental redirection of the 

energy sector. As indicated in the RIA 

for this rule, we expect that the main 

impact of this rule on the nation’s mix 

of generation will be to reduce coal-fired 

generation, but in an amount and by a 

rate that is consistent with recent 

historical declines in coal-fired 

generation. Specifically, from 

approximately 2005 to 2014, coal-fired 

generation declined at a rate that was 

greater than the rate of reduced coalfired generation that we expect to result 

from this rulemaking from 2015 to 2030. 

In addition, under this rule, the trends 

for all other types of generation, 

including natural gas-fired generation, 

nuclear generation, and renewable 

generation, will remain generally 

consistent with what their trends would 

be in the absence of this rule. In 

addition, this rule is expected to result 

in increases in demand-side EE. 

In addition, contrary to claims of 

some commenters, in this rule, the EPA 

is not attempting to expand its 

authorities by attempting to expand the 

jurisdiction of the CAA to previously 

unregulated sectors of the economy, in 

contravention of the UARG decision. In 

UARG, the U.S. Supreme Court struck 

down the EPA’s interpretation of the 

PSD provisions of the CAA because the 

interpretation had the effect of applying 

the PSD requirements to large numbers 

of small sources that previously had not 

been subject to PSD, and because, 

according to the Court, the EPA 

acknowledged that Congress did not 

intend that such sources be subject to 

the PSD requirements.618 Commenters 

appear to interpret this decision to 

preclude the EPA from including at 

least building block 3 in the BSER 

because it includes measures that 

involve entities (such as RE developers) 

that do not emit CO2 and have not 

previously been subject to the CAA. 

However, in this rule, the EPA is not 

attempting to subject any entity other 

than the affected EGUs in the source 

category to CAA section 111 

requirements. As discussed below, the 

EPA is not finalizing the proposed 

portfolio approach, under which states 

were authorized to include, in their 

CAA section 111(d) state plans, 

federally enforceable requirements on 

entities other than affected EGUs. Thus, 

as noted above, this final rule does not 

require or authorize the states to include 

entities other than affected EGUs in 

their CAA section 111(d) state plans, 

and as a result, those entities will not 

come under CAA jurisdiction 619 and 

the parts of the economy that they 

represent will not be regulated by the 

EPA. 

7. Relative Stringency of Requirements 

for Existing Sources and New, Modified, 

and Reconstructed Sources 

Commenters also objected that the 

proposed CAA section 111(d) standards 

are more stringent than the standards for 

new, modified or reconstructed sources, 

and they assert that setting CAA section 

111(d) standards that are more stringent 

than CAA section 111(b) standards 

would be illogical, contrary to 

precedent, contrary to the intent of the 

remaining useful life exception, and 

arbitrary and capricious.620 We disagree 

with these comments. Comparing the 

control requirements of the two sets of 

rules, CAA section 111(d) and 111(b), is 

an ‘‘apples-to-oranges’’ comparison and, 

as a result, it is not possible—and it is 

overly simplistic—to conclude that the 

CAA section 111(d) requirements are 

more stringent than the CAA section 

111(b) requirements. 

Most importantly, the two sets of 

rules become applicable at different 

points in time and have significantly 

different compliance periods. The CAA 

section 111(b) rule becomes applicable 

for new, modified and reconstructed 

sources immediately upon construction, 

modification, or reconstruction and, in 

fact, by operation of CAA section 111(e) 

and (a)(2), new, modified, or 

reconstructed sources that commenced 

construction prior to the effective date 

of the CAA section 111(b) rule must also 

be in compliance upon the effective date 

of the rule. In contrast, the requirements 

under the CAA section 111(d) rule do 

not become applicable to existing 

affected EGUs until seven years after 

promulgation of the rule, when the 

interim compliance period begins in 

2022, and the final compliance period 

does not begin until 2030. Moreover, the 

compliance period for the interim 

requirements is eight years. This later 

applicability date and longer 

compliance period for existing sources 

accommodates a requirement that, on 

average, those sources have a lower 

nominal emission limit than the 

standards for new or modified sources, 

which those latter sources must comply 

with immediately. 

In addition, the timetables for 

compliance with the CAA section 111(b) 

and 111(d) rules should be considered 

in light of the 8-year review schedule 

required for CAA section 111(b) rules 

under CAA section 111(b)(1)(B). Under 

CAA section 111(b)(1)(B), the EPA is 

required to ‘‘review and, if appropriate, 

revise’’ the CAA section 111(b) 

standards ‘‘at least every 8 years.’’ This 

provision obligates the EPA to review 

the CAA section 111(b) rule for CO2

emissions from new, modified, and 

reconstructed power plants by the year 

2023. That mandatory review will 

reassess the BSER to determine the 

appropriate stringency for emission 

standards for new, modified, and 

reconstructed sources into the future. 

Therefore, for present purposes of 

comparing the stringency of the CAA 

section 111(b) and 111(d) rules, the year 

2023 presents an important point of 

comparison. 

Specifically, as noted above, the CAA 

section 111(b) standards apply to new, 

modified and reconstructed sources 

beginning in 2015, while the CAA 

section 111(d) rule does not take effect 

until 2022, which happens to fall on the 

cusp of the 8-year review for the CAA 

section 111(b) standards. 

Even after the section 111(d) rule 

takes effect in 2022, the flexibility that 

this rule offers the states has important 

implications for its stringency and for 

any comparison to the CAA section 

111(b) rule. Although the requirements 

for the CAA section 111(d) rule begin in 

2022, they are phased in, in a flexible 

manner, over the 2022–2030 period. 

That is, states are required to meet 

interim goals for the 2022–2029 period 

by 2029, and the final goals by 2030, but 

states are not required to impose 

requirements on their sources that take 


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621A state that chooses to allow its sources to 

remain uncontrolled through 2023 would still be 

able to meet its interim goal by 2029, although it 

would need to impose more stringent requirements 

on its sources over the 2024–2029 period than it 

would if it had imposed requirements beginning in 

2022. It should also be noted that in fact, most states 

could allow their sources to remain uncontrolled 

for 2022 and 2023, and require controls beginning 

in 2024, and still be able to meet their interim goal. 

622 In addition, because the section 111(d) 

requirements are phased in, states may choose to 

apply a gradual phase-in of the reductions. This 

means that the nominal emission rates for section 

111(d) sources would be significantly less stringent 

for the first several years of the compliance period. 

We estimate that if states choose to impose the 

section 111(d) requirements in a proportional 

amount each year, beginning in 2022, the 

requirements for steam generators by 2022 would 

result in an average emission performance rate of 

1,741 lb. CO2/MWh net and by 2023, an average 

emission rate of 1,681 lb. CO2/MWh net (In 2030, 

the rate falls to 1,305 lb. CO2/MWh net.) For 

existing NGCC units, if states choose to implement 

the section 111(d) requirements proportionally, in 

2022, the average rate would be 898 lb. CO2/MWh 

net, and in 2023 it would be 877 lb. CO2/MWh net. 

(In 2030, this rate falls to 771 lb. CO2/MWh net.) 

623See, e.g., EPA, ‘‘Improving Air Quality with 

Economic Incentive Programs,’’ EPA–452/R–01– 

001, at 82 (2001) (requiring that Economic Incentive 

Programs show an environmental benefit, such as 

‘‘reducing emission reductions generated by 

program participants by at least 10 percent’’), 

available athttp://www.epa.gov/airquality/advance/ 

pdfs/eipfin.pdf; ‘‘Economic Incentive Program 

Rules: Final Rule,’’ 59 FR 16690 (April 7, 1994) 

(same); ‘‘Certification Programs for Banking and 

Trading of NOX and PM Credits for Heavy-Duty 

Engines: Final Rule,’’ 55 FR 30584 (July 26, 1990) 

(requiring that for programs for banking and trading 

of NOX and PM credits for gasoline, diesel and 

methanol powered engines, all trading and banking 

of credits must be subject to a 20 percent discount 

‘‘as an added assurance that the incentives created 

by the program will not only have no adverse 

environmental impact but also provide an 

environmental benefit.’’). 

624As explained in the 111(b) preamble, any 

attempt to subcategorize and assign a lower 

emission limit to larger, non-rapid start NGCC units 

could cause market distortions. 625The section 111(b) standards for modified and 

reconstructed steam generation units are generally 

lower than the emission rates of existing stream 

generation units, but for the reasons explained 

earlier, those standards cannot be compared to the 

section 111(d) standards for existing steam 

generation units. 

effect in 2022. In fact, states may, if they 

prefer, impose business-as-usual 

emission standards on their sources that 

do not require emission reductions in 

2022 and apply emission standards on 

their sources that do require emission 

reductions and that take effect no earlier 

than 2023. Moreover, because emission 

standards may have an annual 

compliance period, the states may allow 

their sources to delay having to comply 

with any emission reduction 

requirements until the end of 2023.621

Therefore, while the CAA section 

111(b) standards apply to new, 

modified, and reconstructed sources 

beginning in 2015, the CAA section 

111(d) standards may not apply to 

existing sources until 2023. As a result, 

by 2023—the year that the CAA section 

111(b) standards are required to be 

reviewed for possible revision—affected 

EGUs subject to the CAA section 111(d) 

standards may remain uncontrolled. 

Under those circumstances, the CAA 

section 111(d) rule cannot be said to be 

more stringent than the CAA section 

111(b) rule.622

Another reason why the section 

111(d) rule cannot be said to be more 

stringent than the section 111(b) rule is 

that for any individual source, the 

section 111(d) rule is applied more 

flexibly and includes more flexible 

means of compliance. Whereas the CAA 

section 111(b) rule entails an emission 

rate that each affected EGU must meet 

on a 12-month (rolling) basis, the CAA 

section 111(d) is more flexible. For 

example, states may adopt the state 

measures approach and refrain from 

imposing any requirements on their 

affected EGUs. In addition, under the 

CAA section 111(d) rule, sources have 

more flexible means of compliance. For 

an emission standards approach, 

depending on the form of the state 

requirements (mass-based or rate-based), 

the state may be expected to authorize 

trading of mass-based emission 

allowances or rate-based emission 

credits, and in addition, the purchase of 

ERCs. These flexibilities are not 

included in the CAA section 111(b) rule, 

rather, as noted, each new, modified, 

and reconstructed EGU must 

individually meet its emission standard 

on a 12-month (rolling) basis. The EPA 

has frequently required that sources 

meet a more stringent nominal limit 

when they are allowed compliance 

flexibility, particularly, the opportunity 

to trade.623 In addition, states have the 

discretion to allow their sources to meet 

emission standards over a longer time 

period. This distinction between the 

two rules is another reason why the 

CAA section 111(d) rule cannot be said 

to be more stringent in fact than the 

CAA section 111(b) rule. 

There are other reasons why the CAA 

section 111(d) rule cannot be said to be 

more stringent. With respect to the CAA 

section 111(d) and 111(b) rules for 

existing and new NGCC units, we note 

the following: As explained in the CAA 

section 111(b) preamble, the standard 

for new NGCC units is designed to 

accommodate a wide range of unit 

types, including small units and rapidstart units, which are a small part of the 

expected new NGCC generation 

capacity. As such, the CAA section 

111(b) standard (1,000 lb CO2/MWh 

gross, which equates to 1,030 lb CO2/

MWh net) will not constrain the 

emissions of the great majority of 

expected new NGCC generation 

capacity, which is expected to consist of 

larger base load units (with a capacity 

of 100 MW or greater) that are not 

intended to cycle frequently. Their 

initial emissions are expected to be 

below 800 lb. CO2/MWh gross, their 

emissions over time may be somewhat 

higher due to equipment deterioration, 

and as a result, their PSD permits are 

expected to include emission limits at 

approximately the 800 lb. CO2/MWh 

gross level. A very small amount of the 

new NGCC generation is expected to be 

small units (with a capacity of 

approximately 25 MW) or rapid-start 

units. Their initial emissions are 

expected to be approximately 950 lb. 

CO2/MWh gross, their emissions over 

time are expected to be somewhat 

higher due to equipment deterioration, 

and it these units that the standard of 

1,000 lb. CO2/MWh gross is designed to 

constrain.624 As a result, the 1,000 lb. 

CO2/MWh gross limit applies to all new 

NGCC units, including the great 

majority of the expected new capacity 

consisting of larger, non-rapid start 

units, even though, as just noted, the 

great majority of the units are expected 

to emit at significantly lower emission 

rates. The CAA section 111(d) standard 

for existing sources, in contrast, is 

generally expected to constrain existing 

NGCC units on average. Moreover, very 

little of the existing NGCC generation 

includes small units or, in particular, 

rapid-start units because the latter are a 

recently developed technology. To some 

extent, the same is true for the 111(b) 

standard for reconstructed NGCC units. 

The average NGCC rate was 

approximately 850 lb CO2/MWh gross in 

2014 and, as a result, most sources are 

emitting below the CAA section 111(b) 

standard for reconstructed sources. For 

these reasons, too, the CAA section 

111(b) standards for new and 

reconstructed NGCC units cannot be 

compared to the 111(d) standards for 

existing NGCC units.625

Moreover, even if commenters were 

correct that the CAA section 111(d) 

requirements for existing sources are 

more stringent than the CAA 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 CAA section 111(b) 

rulemaking, we explain the basis for the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64787 

626Typically, 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. 

627Similarly, within each interconnection, the 

generation-weighted 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). 

628See, e.g., 79 FR 34830, 34859 (June 18, 2014). 

BSER for new sources, and why we do 

not include certain measures, such as 

the building blocks. As long as the BSER 

determination is reasonable and the 

resulting emission limits meet other 

applicable requirements, those emission 

limits are valid, even if the one for new 

sources is less stringent than the one for 

existing sources. No provision in section 

111, nor any statement in its legislative 

history, nor any of its case law, 

indicates that the standards for new 

sources must be more stringent than the 

standards for existing sources. 

C. Building Block 1—Efficiency 

Improvements at Affected Coal-Fired 

Steam EGUs 

The first category of approaches to 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs consists of 

measures that improve heat rate at coalfired steam EGUs. Heat rate 

improvements are changes implemented 

at an EGU that increase the efficiency 

with which the EGU converts fuel 

energy to electric energy, thereby 

reducing the amount of fuel needed to 

produce the same amount of electricity 

and consequently lowering the amount 

of CO2 produced as a byproduct of fuel 

combustion. Heat rate improvements 

yield important economic benefits to 

affected EGUs by reducing their fuel 

costs. 

An EGU’s heat rate is the amount of 

fuel energy input needed (Btu, higher 

heating value basis) to produce 1 kWh 

of net electrical energy output.626 In 

2012, the generation-weighted average 

annual heat rate of the 884 coal-fired 

EGUs included in EPA’s building block 

1 analysis was approximately 9,732 Btu 

per gross kWh.627 Because an EGU’s 

CO2 emissions are driven primarily by 

the amount of fuel consumed, 

improving (i.e., decreasing) heat rate at 

a coal-fired EGU inherently reduces the 

carbon-intensity of generation. 

As discussed above in section V.A 

and in the June 2014 proposal,628 it is 

critical to recognize that affected coalfired EGUs operate in the context of the 

integrated electricity system. Because of 

this reality, applying building block 1 in 

isolation can result in a ‘‘rebound 

effect’’ that undermines the emissions 

reductions otherwise achieved by heat 

rate improvements. As already noted, 

the building block 1 measures described 

below cannot by themselves constitute 

the BSER because the quantity of 

emission reductions achieved—which is 

a factor that the courts have required 

EPA to consider in determining the 

BSER—would be of insufficient 

magnitude in the context of this 

pollutant and this industry. The 

potential rebound effect, if it occurred, 

would exacerbate the insufficiency of 

the emission reductions. However, 

applying building block 1 in 

combination with other building blocks 

can address this concern for the reasons 

stated in section V.A.4. 

We conducted several analyses to 

assess the potential for heat rate 

improvements from the coal-fired EGU 

fleet. As in the proposal, we employed 

a unit-specific approach that compared 

each EGU’s performance against its own 

historical performance in lieu of directly 

comparing an EGU’s performance 

against other EGUs with similar 

characteristics. Accordingly, as 

described below, our method effectively 

controls for the characteristics and 

factors of an EGU that typically remain 

constant over time (e.g., a unit is 

unlikely to dramatically increase or 

decrease in size). Our methodology for 

determining the amount of heat rate 

improvement appropriately included in 

the BSER as building block 1 is 

discussed in the next section, below. 

1. Summary of Measures Comprising the 

BSER in Building Block 1 

a. Measures under building block 1— 

heat rate improvements. 

In finalizing the building block 1 

portion of this rule, we considered over 

a thousand individual comments from 

the public, including individual EGUs 

and state agencies, on heat rate 

improvement, which are discussed 

below and also in the responses to 

comments document and the GHG 

Mitigation Measures TSD for the CPP 

Final Rule. 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 coal-fired 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 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 doublecounted 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. 

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 doublecounting, 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 


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64788 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

629Sargent and Lundy 2009, Coal-Fired Power 

Plant Heat Rate Reductions, SL–009597, Final 

Report, January 2009, available at: http://

www.epa.gov/airmarkets/documents/ipm/

coalfired.pdf. 

630The 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. 

631Because 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. 

632As described below, we also conducted this 

regionalized approach using a benchmark based on 

the best hourly gross heat rate accounting for 

outliers during any one-year period. See the GHG 

Mitigation Measures TSD supporting the final CPP 

for more details. 

633 In the proposal, we used heat input values 

rather than gross heat rate values. See the GHG 

Mitigation Measures TSD supporting the final CPP 

for more details. 

634For the Eastern Interconnection, the 

consistency factor is 38.1 percent. For the Western 

Interconnection, the consistency factor is 38.4 

percent. For the Texas Interconnection, the 

consistency factor is 37.1 percent. Conducting this 

analysis on a nationwide basis would have resulted 

in application of a consistency factor of 38.2 

percent. As described below, we also conducted 

this regionalized approach using consistency factors 

determined based on one-year figures. See the GHG 

Mitigation Measures TSD supporting the final CPP 

for more details. 

(including measures that are 

unambiguously equipment upgrades, 

such as turbine overhauls) are possible 

at many coal-fired EGUs, as supported 

by numerous commenters, the Sargent & 

Lundy study 629 (S&L) and other 

industry reports and studies. Many of 

these reports and studies are referenced 

in the TSD developed for the proposed 

rule, as well as in the GHG Mitigation 

Measures TSD supporting the final CPP. 

Several commenters criticized the fact 

that the proposal assessed potential heat 

rate improvement on a nationwide 

basis. These commenters suggested 

instead that we narrow the geographic 

scope of our analysis, generally 

identifying a state-by-state approach as 

a preferred alternative. In light of 

commenters’ concerns about using a 

single nationwide approach, as well as 

for reasons described in Section V.A 

and elsewhere in this preamble, the 

final rule assesses potential heat rate 

improvement regionally, within the 

Eastern, Western and Texas 

Interconnections.630

For the final rule, we performed 

several analyses to determine what heat 

rate improvement was achievable in 

each interconnection from best practices 

and equipment upgrades. As in the 

proposal, these analyses used the 11- 

year dataset of EGU hourly gross heat 

rate data from 2002 to 2012. As 

discussed further in the GHG Mitigation 

Measures TSD, our reliance on these 

gross heat rate data was reasonable 

given that (1) these data are the only 

comprehensive data available to the 

EPA, and (2) heat rate is proportional to 

CO2 emission rate. 

As in the proposal, we used more 

than one analytical method to evaluate 

the opportunity for EGUs to reduce their 

CO2 emissions through heat rate 

improvements. Our final methodology 

uses three different analytical 

approaches based on refinements of the 

two approaches described at the 

proposal stage. We call these final 

approaches: (1) The ‘‘efficiency and 

consistency improvements under 

similar conditions’’ approach; (2) the 

‘‘best historical performance’’ approach; 

and (3) the ‘‘best historical performance 

under similar conditions’’ approach. As 

described below and in the GHG 

Mitigation Measures TSD, each 

approach provides an independently 

reasonable way to estimate the potential 

for heat rate improvements by EGUs in 

each region. However, rather than select 

a potential heat rate improvement value 

supported by one or only some of these 

independently reasonable analytical 

approaches, we conservatively based 

our final determination for each region 

on the value for that region supported 

by all three approaches. 

The ‘‘efficiency and consistency 

improvements under similar 

conditions’’ approach is a slight 

refinement of an approach discussed at 

length in the proposal. As in the 

proposal, we distributed each hour of 

gross heat rate data for each EGU into 

a matrix comprised of 168 bins, based 

on the ambient temperature and hourly 

capacity factor of the EGU at the time 

that hour of gross heat rate data was 

generated. Each bin represented a 10- 

degree Fahrenheit (°F) range in ambient 

temperature (from ¥20 °F to greater 

than 110 °F), and a 10-percent range in 

capacity factor (from 0 percent to greater 

than 110 percent 631). 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 70 °F and 

79 °F. 

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 twoyear period.632 We compared the hourly 

gross heat rate data within each bin to 

the EGU’s benchmark value. Similar to 

the proposal, within each bin we 

assessed the effect on heat rate of 

improving the consistency of that EGU 

by reducing hourly gross heat rate 

values that were greater than the 

benchmark by a percentage of the 

distance between each of those higher 

hourly values and the benchmark.633

We refer to this percentage 

improvement value as the ‘‘consistency 

factor,’’ because applying it results in 

values for heat rate that are more 

consistent with the EGU’s benchmark 

for that bin. In our proposal we 

evaluated the heat rate improvement 

that would result from applying 

consistency factors of 10, 20, 30, 40 and 

50 percent of the distance between those 

less-efficient hourly gross heat rate 

values and the benchmark; using 

engineering judgment, we selected a 

consistency factor of 30 percent, which 

produced results comparable to those 

obtained using other approaches for 

analyzing heat rate. For our final 

analysis under this approach, we 

refined the consistency factor based on 

a statistical assessment of the overall 

variability of heat rate in that EGU’s 

region, as described in the GHG 

Mitigation Measures TSD.634 As in the 

proposal, we applied the consistency 

factor to each bin of each EGU’s hourly 

gross heat rate data, and averaged the 

result across all bins in that EGU’s 

matrix. The net result was an improved 

gross heat rate reflecting what that EGU 

would have achieved between 2002 and 

2012 if, under certain ambient 

temperature and capacity factor 

conditions, the EGU had improved its 

gross heat rate during less-efficient 

hours to be slightly more consistent 

with the relevant benchmark value. We 

then compared the improved gross heat 

rate for each EGU to its actual 2012 

historical average gross heat rate. We 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64789 

635Conducting 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 oneyear averages. 

636As described below, we also conducted this 

regionalized approach using each EGU’s best oneyear rolling average. See the GHG Mitigation 

Measures TSD supporting the final CPP for more 

details. 637Conducting 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. 

638As 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. 

639Conducting 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. 

640The GHG Mitigation Measures TSD describes 

in more detail our rationale for using one- and twoyear averaging periods in our analytical approaches 

and methodology as a whole. 

chose 2012 as the year of comparison 

because 2012 was the latest year for 

which the EPA had data at the time of 

the proposal, and because using the 

most recent data reflects the EGU’s 

current operating level and accounts for 

improvements the EGU may have 

undertaken over the 11-year study 

period. 

Applying this procedure to all units 

in our database and averaging the 

generation-weighted results, we 

determined that it would be reasonable 

to conclude that, through application of 

best practices and equipment upgrades, 

EGUs on average are at least capable of 

reducing their CO2 emissions by 

improving heat rate 4.3 percent in the 

Eastern Interconnection, 2.1 percent in 

the Western Interconnection, and 2.3 

percent in the Texas Interconnection.635

In addition to the statistical approach 

described above, we employed a ‘‘best 

historical performance’’ approach 

refined from the proposal, which 

compared each EGU’s best two-year 

rolling average gross heat rate to that 

EGU’s 2012 average annual gross heat 

rate.636 We then calculated the 

differences across all EGUs in a region 

to determine the potential heat rate 

improvement that would result if, in 

2012, each EGU had performed at the 

best two-year rolling average gross heat 

rate that the EGU achieved between 

2002 and 2012. Under this analysis of 

historical gross heat rate, we determined 

that it would be reasonable to conclude 

that the average heat rate improvement 

potential from best practices and 

equipment upgrades is at least 4.9 

percent in the Eastern Interconnection, 

2.6 percent in the Western 

Interconnection and 3.1 percent in the 

Texas Interconnection.637

Finally, we employed the ‘‘best 

historical performance under similar 

conditions’’ approach, which combines 

aspects of the other two approaches. 

First, as with the ‘‘efficiency and 

consistency improvements under 

similar conditions approach,’’ we 

grouped hourly data for each EGU by 

ambient temperature conditions and 

hourly capacity factor. Next, we 

calculated each EGU’s best two-year 

gross heat rate for each of the 168 

ambient temperature-capacity factor 

bins.638 Similar to the ‘‘best historical 

performance’’ approach, to calculate the 

potential heat rate improvement, the 

EPA then compared each EGU’s 2012 

gross heat rate for each of the ambient 

temperature-capacity factor bins to the 

EGU’s best two-year gross heat rate for 

the corresponding bin. Accounting for 

differences in ambient temperature and 

capacity factor, we determined that 

under this analytical approach the 

average heat rate improvement potential 

from best practices and equipment 

upgrades was at least 5.3 percent in the 

Eastern Interconnection, 3.1 percent in 

the Western Interconnection and 3.5 

percent in the Texas Interconnection.639

As in the proposal, we additionally 

analyzed the data with our analytical 

approaches using one-year averaging 

periods in place of the two-year 

averaging periods described above.640

However, because our conservative 

overall methodology adopts the lowest 

value that is identified for a region by 

any of our reasonable analytical 

approaches, the inherently less 

conservative results obtained with oneyear averaging periods (reproduced 

below) could not influence the outcome 

of our methodology as a whole. Overall, 

applying these three analytical 

approaches resulted in six heat rate 

improvement values generated for each 

region, each of which represents a 

reasonable estimate of the potential for 

heat rate improvements by EGUs in that 

region. Those values ranged from 4.3 to 

6.9 percent in the Eastern 

Interconnection, from 2.1 to 4.7 percent 

in the Western Interconnection, and 

from 2.3 to 4.9 percent in the Texas 

Interconnection. In all three regions, the 

most conservative values were 

generated using the ‘‘efficiency and 

consistency improvements under 

similar conditions’’ approach with twoyear 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 historical performance .............................................................................. 4.1 2.6 4.2 3.1 6.3 4.9 

Best historical performance under similar conditions ....................................... 4.7 3.1 4.9 3.5 6.9 5.3 

Accordingly, we have concluded that 

a well-supported and conservative 

estimate of the potential heat rate 

improvements (and accompanying 

reductions in CO2 emission rates) that 

EGUs can achieve on average through 

best practices and equipment upgrades 

is a 4.3-percent improvement in the 

Eastern Interconnection, a 2.1-percent 

improvement in the Western 

Interconnection and a 2.3-percent 

improvement in the Texas 

Interconnection. The decision to use 

these values as the building block 1 

potential in each region is based on the 

weight of evidence that these are 

conservative values; for each region, 

each of the three analytical approaches 

in our methodology supports our 

determination that the heat rate 

improvement value we selected is 


tkelley on DSK3SPTVN1PROD with BOOK 2
64790 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

641To give an illustrative example, imagine a 

population of sources that emit Pollutant X. Half of 

the sources emit Pollutant X at 2500 lbs/hour, while 

the other half of the sources have scrubbers 

installed that reduce their emission rates to 1500 

lbs/hour. Because the sources are evenly divided 

between those with and without scrubbers, the 

average emission rate for the population as a whole 

is 2000 lbs/hour. In this hypothetical, EPA decides 

to base requirements on the emission rate 

achievable through use of a scrubber, meaning that 

all sources will have to meet an emission rate of 

1500 lbs/hour. Because the fleet as a whole has an 

average emission rate of 2000 lbs/hour, it would be 

accurate for EPA to say that the fleet as a whole can 

reduce its emission rate by 25 percent—from 2000 

lbs/hour on average (only half the sources with 

scrubbers), to 1500 lbs/hour on average (all the 

sources with scrubbers). This description of what is 

possible for the fleet as a whole—a 25-percent 

reduction in emission rate—should not be 

misinterpreted as a statement that every individual 

source is capable of further reducing its emissions 

by 25 percent. The sources that have already 

installed scrubbers, and which are thus already 

operating at 1500 lbs/hour, would not be required 

to further improve their emission rate. 

642Examples 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 onsite 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. 

643Had the EPA maintained a nationwide 

approach to analyzing the potential reductions 

under building block 1, the result would have been 

4.0 percent. 

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 application of best practices 

and some of the available equipment 

upgrades. A more detailed discussion of 

the EPA’s analysis in determining the 

heat rate improvement potential for 

existing coal-fired EGUs may be found 

in the GHG Mitigation Measures TSD 

supporting the final CPP. 

No affected coal-fired EGU is 

specifically required to improve heat 

rate by any amount as a result of this 

rule. Rather, as described in section VI, 

the potential for heat rate improvement 

is used to determine a CO2 emission 

performance rate. Those affected EGUs 

that have done the most to reduce their 

heat rate will tend to be closer to that 

CO2 emission rate. In this sense, our 

approach to determining potential CO2

reductions through heat rate 

improvements is similar to the way EPA 

ordinarily approaches standards of 

performance.641

In this final analysis, we do not 

delineate what proportion of the 

potential heat rate improvement can be 

expected from equipment upgrades 

versus best practices; 642 only that these 

heat 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 coal-fired 

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 regionspecific 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 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 applied this methodology on a 

regional basis and reduced the overall 

expected percentage 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.643 These values 

reflect improvements achievable 

through both best practices and 

equipment upgrades because, as 

described above, we also no longer 

include a separate estimation of the 

potential heat rate improvement 

achievable solely through equipment 

upgrades. 

We received comments on our 

proposed statistical methodology for 

determining the CO2 emission 

reductions opportunities achievable by 

coal-fired EGUs through heat rate 

improvements. We have closely 

reviewed those comments and, for the 

final rule, have made refinements to our 

methodology, as described above and 

explained in more detail in the GHG 

Mitigation Measures TSD supporting the 

final CPP. 

In the final rule, the EPA extends the 

implementation deadline from 2020 to 

2022. This additional time will be 

helpful to the states seeking to conduct 

more targeted analyses of the nature and 

extent of heat rate improvements that 

specific coal-fired 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 


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644The $100/kW cost figure from the proposal is 

now particularly conservative because it included 

the cost of significant equipment upgrades that 

improve heat rate, whereas building block 1 is now 

largely quantified based on low- or no-cost best 

practices, with a smaller portion of the remainder 

comprised of equipment upgrades. 

changes to heat rate monitoring methods 

at EGUs and for the installation of new 

pollution controls that comply with 

other rules, as discussed below in the 

summary of key comments. 

2. Costs of Heat Rate Improvements 

By definition, any heat rate 

improvement made by EGUs for the 

purpose of reducing CO2 emissions will 

also reduce the amount of fuel that 

EGUs consume to produce the same 

electricity output. The cost attributable 

to CO2 emission reductions, therefore, is 

the net cost of achieving heat rate 

improvements after any savings from 

reduced fuel expenses. As summarized 

below, we estimate that, on average, the 

savings in fuel cost associated with the 

percentage heat rate improvements we 

identified for each region would be 

sufficient to cover much of the 

associated costs. Accordingly, the net 

costs of heat rate improvements 

associated with reducing CO2 emissions 

from affected EGUs are relatively low. 

We recognize that this cost analysis will 

represent the costs for some EGUs better 

than others because of differences in 

individual circumstances. We further 

recognize that reduced generation from 

coal-fired EGUs due to the 

implementation of other building block 

measures would tend to reduce the fuel 

savings associated with heat rate 

improvements, thereby raising the 

effective cost of achieving the CO2

emission reductions from the heat rate 

improvements. Nevertheless, we still 

expect that a significant fraction of the 

investment required to capture the 

technical potential for CO2 emission 

reductions from heat rate improvements 

would be offset by fuel savings, and that 

the net costs of implementing heat rate 

improvements as an approach to 

reducing CO2 emissions from affected 

EGUs are reasonable. Even if we 

conservatively estimate that EGUs will 

largely rely on equipment upgrades 

rather than cheaper best practices to 

reduce heat rate, those reductions can 

generally be achieved at $100 or less per 

kW, or approximately $23 per ton of 

CO2 removed, as described in detail in 

the GHG Mitigation Measures TSD 

supporting the final CPP.644 Depending 

on the balance between equipment 

upgrades and best practices, improving 

heat rate would even result in a net 

savings for some EGUs. 

Based on the analyses of technical 

potential and cost summarized above 

and in Chapter 2 of the GHG Mitigation 

Measures TSD, we find that heat rate 

improvements of 4.3, 2.1 and 2.3 

percent are reasonable and conservative 

estimates of what coal-fired EGUs in the 

Eastern, Western and Texas 

Interconnections, respectively, can 

achieve at a reasonable cost. 

3. Response to Key Comments 

Many commenters said that the EPA 

should have subcategorized by EGU 

design or operating characteristics for 

purposes of evaluating potential heat 

rate improvements under building block 

1. 

Several studies categorize EGUs 

broadly by capacity, thermodynamic 

cycle, fuel rank or other characteristics. 

We considered subcategorizing the 

EGUs by their design and fuel 

characteristics under building block 1. 

Although grouping by categories does 

not account for all of the factors that 

may affect heat rate, it can provide a 

useful way of understanding the 

operating profile of classes of coal-fired 

EGUs and the fleet as a whole. However, 

we have declined to subcategorize 

among affected coal-fired EGUs for both 

technical and practical reasons. First, as 

discussed above, our assessment of heat 

rate improvement potential uses a unitspecific data methodology that 

compares each EGU’s performance 

against its own historical performance. 

By substantially basing our analysis on 

these unit-specific assessments, we 

inherently factor in the effect of 

numerous design conditions. We also 

conducted a regression analysis that 

evaluated the effect of numerous factors 

on heat rate, and found that 

subcategorizing would generally make 

little difference in our analysis. 

Additionally, subdividing the EGUs into 

subcategories would reduce the quantity 

of EGUs used to calculate each average, 

which would increase the influence of 

random and atypical variations in the 

data on the overall averages, and would 

thus decrease our confidence in the 

results. Furthermore, as a practical 

matter, states are free to apportion 

reductions in a way that reflects any 

subcategories of their choosing when 

determining the emission standards for 

individual affected EGUs. Additionally, 

commenters assert that because building 

block 1 is calculated on an average 

basis, some affected EGUs will have 

greater potential than others to reduce 

CO2 emissions through heat rate 

improvements. If an affected EGU 

cannot meet its particular emission 

standard because it has below-average 

potential to reduce emissions through 

heat rate improvements, then in 

instances where the EGU’s state plan 

allows emissions trading, the EGU can 

acquire credits or allowances from 

affected EGUs that have above-average 

potential. For a further discussion of our 

reasonable decision not to subcategorize 

among coal-fired EGUs for purposes of 

determining building block 1, see the 

GHG Mitigation Measures TSD 

supporting the final CPP. 

Many commenters told the EPA that 

EGUs already have undertaken 

significant efforts to operate efficiently 

to provide reliable electric service at the 

lowest reasonable cost; that they believe 

they cannot significantly improve heat 

rate; that best practice maintenance 

activities are performed on a daily basis, 

including during maintenance outages 

that allow for the inspection, cleaning 

and repair of all equipment; that 

extensive capital investments have been 

made to install state-of-the art 

equipment and replace equipment that 

is beyond repair; and that their 

employees continuously monitor and 

control operating levels in the 

combustion process to maintain 

maximum combustion of fuel and to 

avoid wasting available heat energy. In 

summary, these commenters say they 

have expended considerable effort and 

resources to maintain peak boiler 

efficiency at all times and, therefore, the 

6-percent heat rate improvement 

proposed for building block 1 is 

unreasonable to apply to EGUs across 

the board; the EPA should develop a 

rule that allows treatment of affected 

EGUs on a case-by-case basis. 

We commend the efforts of those who 

strive to operate and maintain EGUs in 

the best possible manner to minimize 

heat loss and CO2 emissions. This rule 

does allow for treatment of EGUs on a 

case-by-case basis. States may believe 

that individual considerations are 

appropriate in some cases and, 

accordingly, we have purposely allowed 

states to make decisions about how to 

implement specific CO2 reductions. Our 

determinations of 4.3-, 2.1- and 2.3- 

percent heat rate improvement for EGUs 

in the Eastern, Western and Texas 

Interconnection, respectively, are 

conservatively based on the lowest 

value identified by any of our 

reasonable statistical analyses. If states 

choose to set limits on individual 

affected EGUs based in part on the 

availability of heat rate improvements, 

the states are free to assess heat rate 

improvements on a more targeted, caseby-case basis that takes into account an 

EGU’s previous heat rate improvement 

efforts, or lack thereof. The fact that 

states (or EGUs complying with state 

requirements) can make case-by-case 


tkelley on DSK3SPTVN1PROD with BOOK 2
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decisions about how to achieve goals 

does not contradict our conservative 

estimates—which are based on millions 

of hours of operating data reported to 

the EPA by EGUs—of how much EGUs 

are capable of improving their heat rate 

in each region overall. Opportunities to 

improve heat rate abound for affected 

EGUs as a whole, as evidenced by the 

fact that the approaches in our statistical 

methodology each included a 

comparison of an EGU’s historical heat 

rate to its 2012 heat rate. Our estimates 

of the potential heat rate improvement 

are additionally conservative because 

they are based purely on comparisons 

among historical gross heat rate data, 

and thus do not reflect available, costeffective opportunities to improve heat 

rate that affected EGUs never 

implemented during the study period. 

Finally, to the extent that an affected 

EGU was in 2012 fully implementing 

every possible best practice for 

improving heat rate, it may still be 

capable of improving heat rate through 

equipment upgrades. 

Other commenters said that a 6- 

percent heat rate improvement overall is 

too high; that the heat rate improvement 

from upgrades are double-counted 

within the data used to determine heat 

rate improvements from best practices; 

and that the 2-percent heat rate 

improvement specifically for upgrades 

was inappropriately based on 

‘‘conceptual’’ improvements from only 

one study. 

We have reduced the 6-percent heat 

rate improvement from the proposed 

rule to three regionalized figures of 4.3 

percent (Eastern), 2.1 percent (Western) 

and 2.3 percent (Texas), as discussed 

above and described in detail in the 

GHG Mitigation Measures TSD 

supporting the final CPP. We expect 

that, on average, affected coal-fired 

EGUs can at a minimum improve heat 

rate in these amounts by implementing 

best practices and equipment upgrades 

identified in the GHG Mitigation 

Measures TSD. These overall heat rate 

improvement figures do not include an 

estimated percentage heat rate 

improvement attributable specifically to 

upgrades. Although we are no longer 

including in our calculation of building 

block 1 a separate 2-percent heat rate 

improvement attributable solely to 

equipment upgrades, this decision is not 

because we believe that our initial 2- 

percent assessment of equipment 

upgrades was incorrect. To the contrary, 

the information presented in the S&L 

study was similar to that in other 

industry reports and studies—many of 

which were referenced in the proposal 

TSD—describing potential heat rate 

improvements at EGUs from all types of 

equipment upgrades. However, we 

recognized that the possibility existed 

that some limited portion of that 2 

percent was also reflected in our 

statistical analyses of historical gross 

heat rate data. In order to ensure that 

our methodology did not double-count 

an indeterminate amount of heat rate 

improvement available through 

equipment upgrades, we conservatively 

set aside the entire additional 2 percent 

attributable solely to equipment 

upgrades. Accordingly, we determined 

the amount of potential heat rate 

improvement in the BSER solely from 

the heat rate analyses described above, 

which account for 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 postcombustion 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 unitspecific data, our methodology 

inherently factors in the possible effects 

of design and fuel characteristics (e.g., 

coal type, boiler type, nameplate 

capacity, age, cooling water system, air 

pollution controls) on heat rate and heat 

rate variability. 

Although cooling water temperature 

likely plays an important role in a coalfired 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 

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 

operations and maintenance (O&M) 

costs for each heat rate improvement 

method that is discussed. As we 

explained in the proposal, the related 

O&M costs of diligently applying best 

practices are relatively small compared 

to the associated capital costs and 

would, therefore, have little effect on 

the economics of heat rate 

improvements. 

Commenters stated that heat rate 

improvement should be set on a basis 

that is narrower than nationwide—for 

example, state-by-state or unit-by-unit. 

The EPA did not propose and is not 

finalizing a rule that sets heat rate 

improvement goals for individual states 

or for individual coal-fired EGUs. 

Instead, in the approved state plans 

developed under this rule, each state 

will set the emission standards for its 

various coal-fired EGUs. In doing so, the 

state may take into account its own view 

of the amount of heat rate improvement 

needed (if any) at specific EGUs, and 

may look to the EPA’s analysis of heat 

rate improvement potential in the 

applicable region as a guide, while 

keeping in mind the CO2 emission 


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645See above for an explanation of gross versus 

net heat rate. 

performance rate. This broad-based 

approach is consistent with the 

traditional rules evaluating the potential 

for emission reductions on a sourcecategory basis, and is consistent with 

the broader goal-setting purpose of this 

rule. Furthermore, the final rule 

establishes a uniform national 

performance rate based on the least 

stringent regional performance rate 

calculated with the building blocks. 

Accordingly, affected EGUs in regions 

not setting the national level have 

emission reduction opportunities 

beyond those reflected in the applicable 

performance rate. 

The heat rate improvement measures 

comprising building block 1 would 

ordinarily be evaluated on a nationwide 

basis. However, in this instance there 

are two good reasons to calculate 

building block 1 on a regionalized basis. 

First, a regionalized approach is 

consistent with the EPA’s approach to 

determining the other building blocks. 

For building block 1, this means that the 

heat rate improvement should reflect 

only as much potential for emission 

reduction from building block 1 as our 

analyses indicate can be achieved on 

average by the affected coal-fired EGUs 

in that region. This ensures that the 

BSER for each region is representative of 

the characteristics and opportunities 

available within that region, rather than 

a less logical combination of 

opportunities in the region and 

opportunities nationwide. Second, a 

regionalized approach provides a more 

representative average of the potential 

heat rate improvement that EGUs in a 

given region are capable of achieving. 

The populations of affected coal-fired 

EGUs in each region differ in some 

respects, as discussed in the GHG 

Mitigation Measures TSD, and the more 

nuanced regionalized approach thus 

indirectly accounts for some of those 

systemic differences. For these and 

other reasons described in Section V.A. 

of the preamble with respect to the 

BSER as a whole, we have reasonably 

based building block 1 on a regionalized 

approach. Applying this regionalized 

approach to building block 1 strikes an 

appropriate balance between the 

proposed nationwide analysis and 

commenters’ suggested state-specific 

analysis, which does not fully reflect the 

interconnected nature of the system 

within which affected coal-fired EGUs 

operate. 

The practical consequence of 

calculating building block 1 on a 

regionalized versus nationwide basis is 

minimal. This is because the CO2

emission performance rates are based on 

the overall performance rate determined 

to be reasonable for EGUs in the Eastern 

Interconnection. Our methodology 

identifies a 4.3 percent potential 

improvement in the Eastern 

Interconnection, compared to a 4.0 

percent figure across all three 

interconnections. 

We further note, along with some 

commenters, that site-specific 

engineering studies or unit-by-unit 

analyses of heat rate improvement 

potential for coal-fired EGUs are not 

available to the EPA; only a small 

number of site-specific case studies are 

available in the public literature. We 

considered that for the EPA to develop 

a comprehensive, unit-by-unit heat rate 

improvement study of nearly 900 coalfired 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 

improvement-estimating 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 

relies on individualized, unit-by-unit 

hourly performance data from 884 EGUs 

provides conservative and reasonable 

regional estimates of heat rate 

improvement potential. Indeed, given 

the conservative nature of our 

methodology, a unit-specific approach 

that evaluates the full range of best 

practices and equipment upgrades 

available at individual EGUs—including 

upgrades not accounted for here— 

would be more likely to result in higher 

overall heat rate improvement figures 

than we are finalizing for building block 

1. Furthermore, site-specific information 

forms the foundation of the EPA’s 

estimated heat rate improvement 

potential, and similar data likely would 

be used in any site-specific heat rate 

improvement engineering study. 

Finally, EGU-specific detailed design 

and operation information is not 

consistently available for all the factors 

that influence heat rate. The EPA has 

used the comprehensive data that are 

available to reasonably and 

conservatively estimate potential heat 

rate improvement in each region. 

Commenters also said that shifting 

electricity generation from coal-fired 

EGUs to other EGUs because of 

measures implemented under other 

building blocks will lower the capacity 

factors of coal-fired EGUs, and thus 

increase, not decrease, their heat rates. 

We expect that most states will 

develop plans that optimize the 

operation of existing coal-fired EGUs 

while utilizing the other building blocks 

and other measures to reduce emissions 

from carbon-intensive generation. From 

our IPM projections, the average annual 

capacity factor of existing coal-fired 

EGUs that are expected to remain in 

operation in 2030 will actually increase 

compared to 2012. This projection— 

which is further described in the GHG 

Mitigation Measures TSD—incorporates 

expected retirements of inefficient units 

and generation shifts away from using 

coal-fired EGUs as peaking units. 

Commenters also noted that the EPA 

used net heat rate in state goals, but 

used gross heat rate in its heat rate 

improvement analysis—potentially 

ignoring the detrimental effect that 

parasitic load from air pollution control 

devices (APCD) and other equipment 

can have on net heat rate. 

The EPA’s variability analysis 

necessarily and reasonably used gross 

output data for each of the 884 EGUs in 

the EPA’s database because they are the 

only publicly available, unit-specific, 

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. 

Commenters also raised concerns that 

the EPA was not taking into account net 

heat rate increases due to additional 

add-on pollution controls that may, for 

some units, be required by other 

rules.645

The results of our statistical analyses 

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 


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646When considered on a regional basis, we 

expect these controls to impact heat rate by 

approximately 0.3 percent in both the Eastern and 

Western Interconnections, and by less than 0.1 

percent in the Texas Interconnection. 

647Furthermore, 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. 

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 

(FGD), 16.6 GW of dry FGD, 24.9 GW of 

selective catalytic reduction (SCR), and 

3.9 GW of selective noncatalytic 

reduction (SNCR). The resulting impact 

from new pollution controls on existing 

coal-fired EGUs’ heat rate is expected to 

be very small, at conservatively less 

than 31 Btu/kWh, or less than 0.3 

percent in 2025.646 After 2025, this 

estimate is particularly conservative 

because the EPA’s cost performance 

models overestimate the parasitic load 

from individual add-on controls for 

future years. Furthermore, at some EGUs 

these newer pollution control devices 

will replace existing pollution control 

devices. Accordingly, for these EGUs, 

the minimal increase in net heat rate 

due to power required to operate new 

controls will be at least partially offset 

by the decrease in net heat rate caused 

by removal of the control devices 

currently in place. For more information 

about this analysis, see the GHG 

Mitigation Measures TSD supporting the 

final CPP. 

Commenters contended that the 11 

years of data used to evaluate potential 

heat rate improvement is too broad, and 

that the population of domestic coalfired 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 flow 

where the monitoring and reference 

method measurements are taken, and 

which options under the Part 75 

emission measurement rules are chosen 

in the application of the various flow 

rate reference methods. In general, more 

accurate stack gas flow monitoring 

methodologies yield lower values that, 

when used to calculate emissions or 

heat input, may lower the heat rate 

values reported to the EPA. 

Some EGUs adopted monitoring 

methodologies that have the potential to 

affect the exactness of the data we used 

for assessing heat rate improvements. 

However, as discussed in detail in the 

GHG Mitigation Measures TSD 

supporting the final CPP, our review of 

the data shows that a relatively small 

amount of the data are affected by these 

changes; we are confident that the 

values adopted for building block 1 are 

conservative and reasonable estimates of 

the potential for heat rate improvement 

in each region. Some changes in 

monitoring methodology would have 

the result of tending to cause us to 

underestimate the potential for heat rate 

improvement. Furthermore, because our 

methodology analyzes percentage heat 

rate improvement based on 2012 gross 

heat rate data, our results are unaffected 

by EGUs that used more accurate 

monitoring methodologies in 2012 or 

used the same monitoring 

methodologies consistently throughout 

the 11-year study period. For these and 

other reasons discussed in detail in the 

GHG Mitigation Measures TSD, we 

remain confident in our results despite 

the marginal differences attributable to 

monitoring methodologies in some of 

the heat rate data for a subset of 

EGUs.647

In terms of concerns with future 

methodological changes, the 

overwhelming majority of the 884 EGUs 

in the dataset we used to assess heat rate 

improvement have already changed 

their stack gas flow monitoring 

methodology in 2012 or earlier. 

Furthermore, extension of the 

compliance date to 2022 for this rule, as 

discussed above, more than adequately 

allows enough time for EGUs to 

determine how to actually improve their 

heat rates and lower CO2 emissions 

while accommodating future changes to 

monitoring methodologies. For a more 

detailed explanation, see the GHG 

Mitigation Measures TSD supporting the 

final CPP. 

Commenters said that there is no 

proof that lowering the heat rate will 

reduce variability or that reduced 

variability will reduce heat rate, i.e., 

correlation does not prove causation. 

As an initial matter, it is important to 

note that for the final rule the EPA used 

three types of statistical analyses to 

evaluate and estimate potential heat rate 

improvements of coal-fired EGUs, and 

only one of these analyses involved any 

consideration of heat rate variability. All 

three types of statistical analyses are 

described in the GHG Mitigation 

Measures TSD supporting the final CPP. 

These commenters are correct that, in 

the abstract, reducing heat rate 

variability only means that heat rate will 

be more consistent—not necessarily 

lower or higher. However, our analysis 

is not an abstract evaluation of the 

potential to reduce variability, as 

commenters suggest, but rather is an 

evaluation of the potential heat rate 

improvement achievable through 

reducing variability—i.e., reducing 

variability to achieve a more 

consistently low heat rate. See the more 

detailed discussion of the statistical 

procedures used for the final rule, 

above. In particular, the application of 

a ‘‘consistency factor’’ in the analyses 

performed for both the proposed and 

final rule demonstrates the potential 

results if each individual EGU operated 

slightly more consistently with the 

lower heat rates that the EGU had itself 

previously achieved under similar 

conditions. 

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 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64795 

648See preamble section II.C.1, History of the 

Power Sector, for background to this discussion. 

649 ‘‘Economic Dispatch: Concepts, Practices and 

Issues’’, FERC Staff Presentation to the Joint Board 

for the Study of Economic Dispatch’’, Palm Springs, 

California, November 13, 2005. A copy of this 

presentation is available in the docket for this rule. 

650 ‘‘Security Constrained Economic Dispatch: 

Definitions, Practices, Issues and 

Recommendations: A Report to Congress’’, Federal 

Energy Regulatory Commission, July 31, 2006. 

651 Ventyx Electric Power Database. 

652Energy Information Administration, Annual 

Energy Outlook 2015 reference case, 

ref2015.d021915a. 

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 fuel-fired EGUs entails an analysis 

of the extent to which fossil steam EGUs 

can shift generation to existing NGCC 

EGUs. In this section, we define 

building block 2 as the gradual shifting 

of generation from existing fossil steam 

to existing NGCC within each region up 

to a maximum NGCC utilization of 75 

percent on a net summer basis. In each 

year of the interim period, this 75 

percent net summer maximum potential 

is subject to a regional limit informed by 

historical growth rates. 

This section summarizes the EPA’s 

analysis supporting that definition. We 

begin by discussing the sector’s ability 

to reduce CO2 emissions by shifting 

generation, including selected 

background information, data on trends 

toward greater NGCC generation, and 

various mechanisms for executing or 

facilitating generation shifts. Next, we 

describe the amount and timing of 

generation shift we have determined to 

be achievable through the building 

block. We then discuss various elements 

supporting our quantification of 

achievable generation shift, including 

the technical feasibility of NGCC units 

to increase generation; historical shifts 

to NGCC generation; considerations 

related to reliability, natural gas 

transmission infrastructure, natural gas 

production, and electricity transmission 

infrastructure; and regulatory flexibility. 

A discussion of costs follows. Finally, 

we respond to certain comments not 

addressed in the preceding discussions. 

1. Demonstration of Ability To Reduce 

CO2 Emissions Through Shifting 

Generation 

a. Background of utility power sector. 

The ability to shift generation from 

higher- to lower-emitting sources is 

compatible with the way EGUs are 

generally dispatched.648 The standard 

approach to dispatching generation is 

through Security Constrained Economic 

Dispatch (SCED), a well-established 

practice in the electric power 

industry.649 As the name indicates, 

SCED has two defining components: 

Economic operation of generating 

facilities and assurance that the electric 

system remains reliable and secure.650

Economic dispatch generally refers to 

shorter-term planning and operations 

from a day ahead through real time. 

During this period, generating units are 

committed—a process known as ‘‘unit 

commitment,’’ in which units are 

committed to be ready to provide 

generation to the system when they will 

be needed—and then dispatched in real 

time to meet the electricity demand of 

the system. Overall changes in the level 

of generation from different facilities are 

also planned over time periods longer 

than this 2-day dispatch period. Over a 

calendar year, for example, units are 

planned and scheduled seasonally or 

monthly to ensure that sufficient 

capacity and energy will be available to 

meet expected loads in an area. Over a 

period of a week, units are committed 

to be prepared to start up or shut down 

to meet forecast loads, and dispatch is 

coordinated within this planning and 

unit commitment framework. This 

process enables system operators to 

respond quickly to short-term changes 

in demand, and also to shift generation 

among different generation types to 

match longer-term requirements and 

goals. 

EGUs using technologies with 

relatively low variable costs, such as 

nuclear units, are for economic reasons 

generally operated at their maximum 

output whenever they are available. 

Renewable EGUs such as wind and solar 

units also have low variable costs, but 

the magnitude and timing of their 

output generally depend on wind and 

sun conditions rather than the 

operators’ discretion. In contrast, fossil 

fuel-fired EGUs have higher variable 

costs and are also relatively flexible to 

operate. Fossil fuel-fired EGUs are 

therefore generally the units that 

operators use to respond to intra-day 

and intra-week changes in demand. 

Because of these typical characteristics 

of the various EGU types, the primary 

opportunities for switching generation 

among existing units available to EGU 

owners and grid operators generally 

consist of opportunities to shift 

generation among various fossil fuelfired units, in particular between coalfired EGUs (as well as oil- and gas-fired 

steam EGUs) and NGCC units. In the 

short term—that is, over time intervals 

shorter than the time required to build 

a new electric generation unit—fossil 

fuel-fired units consequently tend to 

compete more with one another than 

with nuclear and renewable EGUs. The 

amount of generation shifting from coalfired 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 coaland oil-fired EGUs to NGCC units, both 

as a result of construction of additional 

NGCC units, and also as a result of 

dispatch of pre-existing NGCC units at 

higher capacity factors. As a result, 

generation from NGCC EGUs in 2012 

reached over four times the level of 

NGCC generation in 2000, while 

generation from coal and oil/gas steam 

EGUs decreased by around one third.651

As we demonstrate in the GHG 

Mitigation Measures TSD, NGCC units 

are capable of operating at higher 

annual capacity factors than they have 

historically, so there remains 

considerable opportunity for increased 

use of existing NGCC units to replace 

generation currently supplied by higheremitting coal and oil/gas steam units. 

The electric utility industry is thus wellpositioned to address the requirements 

of this building block by increasing use 

of existing NGCC units and 

correspondingly decreasing use of steam 

units. The electric industry has been 

shifting generation to NGCC units in 

recent years and is expected to continue 

to retire coal capacity and add new 

NGCC capacity. In the reference case 

without implementation of CO2

emission limitations, EIA forecasts 40 

GW of coal retirements and 53 GW of 

NGCC capacity additions from 2014 to 

2030.652 An EPA review of state 

Integrated Resource Plans (IRPs) shows 

a pattern of shifting away from coal 

steam capacity to NGCC capacity and, in 

some cases, conversion of coal steam 

capacity to natural gas steam capacity. 

For example, Ameren plans to add 600 

MW of NGCC capacity and convert two 

coal units to natural gas steam units, 

and Duke plans to add 680 MW of 


tkelley on DSK3SPTVN1PROD with BOOK 2
64796 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

653For further examples, see the memo entitled 

‘‘Review of Electric Utility Integrated Resource 

Plans’’ (May 7, 2015) available in the docket. 

654Regulatory Assistance Project, Electricity 

Regulation in the US: A Guide, Page 9, March 2011. 

Available at http://www.raponline.org/docs/RAP_

Lazar_ElectricityRegulationInTheUS_Guide_2011_

03.pdf. 

655See the Regulatory Impact Analysis. 

656SNL Energy. Data used with permission. 

Accessed May 2015. 

NGCC capacity and convert one coal 

unit to a natural gas steam unit.653

c. Mechanisms for dispatch shifts 

from coal-fired to natural gas-fired 

generation. 

There are a variety of patterns of 

ownership and operational control of 

EGUs; these ownership and operational 

structures influence how EGUs will 

respond to this building block. 

However, all owners and operators have 

the ability to comply by using this 

building block. In terms of ownership, 

investor-owned utilities (IOUs) serve 

about 75 percent of the US population, 

while consumer-owned utilities serve 

the remaining 25 percent.654 In states 

that have maintained traditional 

regulation, IOUs are generally vertically 

integrated (owning generating capacity 

as well as transmission and distribution 

infrastructure), and the wholesale sales 

of these EGUs are regulated by the state; 

in states that have deregulated their 

retail service, ownership of the EGU is 

separated from ownership of 

transmission, and wholesale sales of 

generation are regulated by FERC. 

Consumer-owned utilities comprise 

municipal utilities, public utility 

districts of various types owned by 

government agencies, nonprofit 

cooperative entities (co-ops), and a 

number of other entities such as Native 

American Tribes. 

Operational control of the dispatch of 

power over the electricity grid is 

superimposed on this pattern of 

ownership. Prior to electricity 

restructuring, this dispatch was 

typically operated by major verticallyintegrated utilities or by public power 

entities. Over the last 15 years, large 

portions of the power grid are now 

independently operated by ISOs or 

RTOs. These entities are regulated by 

FERC and dispatch power from multiple 

owners to meet the loads on the bulk 

power grid. 

The combination of multiple 

ownership and types of operational 

control adds to the complexity of 

electricity dispatch, but all affected 

EGUs, regardless of ownership and type 

of control, can use this building block 

to comply with the final rule. The 

principal difference among the differing 

entities lies in the types of methods that 

are available for the affected EGU owner 

to bring about the shift in generation 

that will make use of this building block 

for compliance. There are several 

alternatives to accomplish this result: 

The owner of the higher-emitting 

affected EGU may also own, or have 

affiliates that own, lower emitting 

generation and thus reduce its own 

generation and use its control over these 

other EGUs to increase their generation; 

an EGU may be able to reduce its 

generation and buy replacement power 

from the market that is lower emitting; 

or the EGU may be able to reduce its 

generation and procure generation from 

a separately-owned lower-emitting EGU. 

These alternatives will be available in 

states with either rate or mass-based 

state plans without any change in their 

general form. Under a rate-based state 

plan, an EGU owner may also be able to 

purchase ERCs and average the ERCs 

into its emission rate for purposes of 

demonstrating compliance with its 

standard of performance. Under 

standards of performance that 

incorporate emissions trading, an EGU 

owner may be able to purchase ratebased emission credits or mass-based 

emission allowances not needed by 

other EGUs and use those credits or 

allowances to help achieve its standard 

of performance. 

The potential to shift generation 

identified for this building block is 

entirely consistent with the existing 

economic dispatch protocols described 

above. State environmental policies can 

shift generation in two ways. The first 

is operational restrictions, such as 

permit limits on the number of hours 

that an EGU can operate in order to 

limit emissions. The second is changes 

in the relative costs of generation among 

different types of EGUs related to 

pollution reduction measures. For 

example, a regulation that necessitates 

the use of a control technology that 

requires the application of a reagent in 

a certain kind of EGU will increase the 

variable cost of operating that plant, 

which in turn may reduce the amount 

of generation it is called upon to deliver 

to the grid through security-constrained 

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 RGGI is an example of a state 

program that has this effect. In the 

present rule, although shifts in the mix 

of generation to address the costs of 

pollution control can lead to higher 

electricity generating costs overall, the 

EPA analysis shows these costs to be 

modest and well below their associated 

benefits.655

Many of the NGCC units are owned by 

the same companies or affiliates that 

also own steam units. In these cases, 

changes in EGU generation can be 

planned by the company or affiliate 

without the need to engage in separate 

market transactions with outside 

parties. Where the affected EGU owner 

is also the dispatch entity, as in most 

traditional market structures, the EGU 

owner will generally have operational 

control over the unit. Environmental 

conditions, such as compliance costs or 

limits on generation, can be factored in 

with fuel costs for purposes of 

determining when the unit is committed 

to be available, how the unit can be 

most efficiently cycled, and at what 

level the unit is dispatched. 

An analysis of generation data from 

steam and NGCC units in 2012 shows 

that 77 percent of the steam generation 

occurred from an EGU that owned, or 

that had an affiliate that owned, NGCC 

generation. Eighty percent of the 

generation shift potential identified in 

this building block (increasing NGCC 

generation up to a 75 percent capacity 

factor on a net basis to replace steam 

generation) could occur among these 

entities that own (either directly or 

through affiliates) both steam and NGCC 

generation.656 These data show that 

most EGU generation relevant for this 

building block is produced by entities 

that own both steam and NGCC 

generation. 

Another alternative available to an 

affected EGU owner that does not also 

own NGCC generation is for the higheremitting 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 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64797 

657Some 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. 

658Stakeholders have recognized that ERCs and 

allowances are an effective tool for EGUs to 

implement the building blocks and achieve their 

standards of performance required under this rule. 

See ‘‘Clean Power Plan Implementation: SingleState Compliance Approaches with Interstate 

Elements,’’ Georgetown Climate Center (May 2015), 

http://www.georgetownclimate.org/sites/

www.georgetownclimate.org/files/GCC_Compliance

ApproacheswithInterstateElements_May2015.pdf. 

costs, or limits on generation can be 

incorporated by the owner into the 

determination of the cost-effective 

generation pattern of its EGUs. 

In regions with organized electricity 

markets (including, but not limited to, 

RTOs or ISOs), the various types of EGU 

owners of higher-emitting sources can 

reduce their generation, and any 

resulting deficit in generation on the 

system can be supplied from other EGUs 

in the region; for example, a coal-fired 

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 emission 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 loweremitting generation. 

EGU owners that do not participate in 

an organized electricity market may 

nevertheless purchase power from the 

wholesale power market. Purchases in 

the wholesale power market can be spot 

purchases, which are typically general 

purchases of system power supplied by 

the EGUs across a region, or contract 

purchases, which may have more 

provider-specific characteristics (such 

as specifying the type of unit that is 

providing the power). Purchases 

between EGUs through the wholesale 

power market will have similar 

emission-lowering properties as 

operation of the organized market 

discussed above, because dispatch in 

balancing areas outside RTOs and ISOs 

also follows a similar economic 

dispatch protocol that is informed by 

each unit’s production costs and 

environmental limitations. 

Under this alternative, the steam 

generators may, in effect, realize 

emission reductions from building block 

2 simply by reducing their generation. 

Steam generators do not need to 

purchase replacement electricity as a 

prerequisite for realizing emission 

reductions from reducing their own 

generation because other generators 

already have an incentive to provide as 

much electricity as load-serving entities 

are willing to buy in order to satisfy 

electricity demand.657 As noted above, 

higher-emitting generation sources will 

have to incorporate correspondingly 

higher costs of pollution reduction into 

their supply bids compared to loweremitting 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 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. 

Where permitted under its state plan, 

an EGU would also be able to meet its 

reduction obligations using ERCs or 

allowances. The particular nature of this 

alternative will depend on how a state 

elects to develop its plan. If a state 

chooses a mass-based approach, the 

EGU would simply need to hold 

allowances to cover its emissions. To 

realize an emission reduction from 

building block 2 under this approach, a 

steam generator would only need either 

to reduce its emissions by reducing its 

generation, which would lead to that 

generator needing fewer allowances to 

cover its emissions under the program, 

or to purchase surplus allowances not 

needed by another EGU that had 

reduced its emissions. In a rate-based 

state, the state may choose to provide 

for compliance through the acquisition 

of tradable ERCs. To realize an emission 

reduction from building block 2 under 

this approach, a steam generator would 

be able to adjust its effective emission 

rate by purchasing ERCs that are 

produced by other sources whose 

emission rates are lower than the 

applicable rate standard. In this fashion, 

a steam generator does not need to 

purchase lower-emitting replacement 

power per se in order to demonstrate an 

emission reduction from this building 

block; instead, the steam generator may 

purchase any ERCs that were produced 

from lower-emitting sources (see section 

VIII for more detail on how state plans 

can use an ERC approach to facilitate a 

rate-based compliance demonstration of 

this type of emission reduction).658

The approaches shown here 

collectively demonstrate that all steam 

generators—regardless of size, location, 

form of ownership, or type of market in 

which they operate—can implement 

building block 2 through some or all of 

the mechanisms described. 

2. Amount and Timing of Generation 

Shift 

The EPA has determined that for 

purposes of quantifying the CO2

emission reductions achievable through 

building block 2, a reasonable amount of 

generation shift is the amount of 

generation shift that would result from 

existing NGCC units, on average, 

increasing their annual utilization rates 

to 75 percent of net summer capacity. 

However, the building block does not 

reflect achievement of this average 

capacity factor at the start of the interim 

period, but instead reflects a glide path 

of increases in NGCC utilization over 


tkelley on DSK3SPTVN1PROD with BOOK 2
64798 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

659 79 FR 34866. 

660 79 FR 64543. 

661US 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. 

the interim period. Below, we discuss 

the glide path, and in the following 

section we discuss the basis for finding 

the 75 percent utilization rate, achieved 

over the period of time consistent with 

the glide path, to be reasonable. 

The EPA received significant public 

comments expressing concern regarding 

the proposal’s incorporation of the full 

building block 2 shift in generation by 

the first year of the interim period. 

These commenters perceived this 

approach as requiring states to achieve 

such a significant portion of the 

required CO2 emission reductions early 

in the interim period that states would 

lack flexibility in when and how they 

may achieve the required emission 

reductions. Other commenters 

expressed concern that the full extent of 

building block 2 would be difficult for 

some states to achieve by the first year 

of the interim period as a result of 

technical, engineering, and 

infrastructure limitations or other 

considerations; that such timing may 

crowd out other cost-effective options 

for emission reductions; and that such 

timing might have negative implications 

for reliability. 

In the proposal, the EPA determined 

that emission reductions are feasible 

and achievable at fossil fuel-fired steam 

EGUs by shifting from more carbonintensive 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 coalfired) to NGCC units, up to a utilization 

of 70 percent on a nameplate capacity 

basis, could be achieved by 2020. In 

contrast, the EPA proposed that 

reductions in CO2 emissions from fossil 

fuel-fired units associated with other 

measures, such as increased utilization 

of RE generating capacity and increased 

demand-side EE, would be achievable 

on a phased-in basis between 2020 and 

2029, reflecting the time needed for 

deployment.659 In light of the concerns 

noted above, in the October 2014 

NODA, the EPA solicited comment on 

potential rationales for phasing in the 

potential to shift generation under 

building block 2.660

As already noted, in the final rule the 

EPA has revised the interim period to 

start in 2022, which itself is a 

meaningful response regarding the 

concerns expressed by commenters 

about the timing of building block 2’s 

generation shift potential. In addition, 

the EPA has evaluated the feasibility 

over time of building block 2 within the 

framework of BSER, and is finalizing a 

change to building block 2 that 

gradually phases in the shift from 

existing fossil steam to existing NGCC 

over the interim period. This phase-in 

allows for additional time to complete 

potential infrastructure improvements 

(e.g., natural gas pipeline expansion or 

transmission improvements) that might 

be needed to support more use of 

existing natural gas-fired generation, 

and provides states with the increased 

ability to coordinate actions taken under 

building block 2 with actions taken 

under building block 3 (deployment of 

new renewable capacity). 

The phase-in schedule applies a limit 

to the maximum building block 2 

potential in each year of the interim 

period based on two parameters. The 

first parameter defines an amount of 

generation shift to existing NGCC 

capacity that is feasible by 2022, and the 

second parameter defines how quickly 

that amount could grow until the full 

amount of NGCC generation could be 

achieved as part of the BSER. Both of 

these parameters are determined by 

examining the extent to which gas-fired 

generation has increased over historical 

time periods. The first parameter is 

based on the single largest annual 

increase in power sector gas-fired 

generation since 1990, which occurred 

between 2011 and 2012 and is equal to 

22 percent.661 We believe that this 

amount is a conservative estimate of the 

ability of the sector to increase 

utilization of NGCC capacity by 2022, 

given that this increase has already 

occurred in a single year. The second 

parameter is based on the average 

annual growth in gas-fired generation in 

the power sector between 1990 and 

2012, which is approximately 5 percent 

per year. 

In the performance rate calculation 

methodology, these two parameters 

constrain the annual rate at which 

building block 2 shifts generation from 

fossil steam units to NGCC units. The 

interim performance rate is an average 

of annual rates calculated over the 

2022–2029 period. The two parameters 

above limit the extent to which NGCC 

generation is able to increase and 

replace fossil steam generation in each 

year of the interim period. In the first 

year, NGCC generation is limited to a 

maximum of a 22 percent increase from 

2012 levels in each region. In each 

subsequent year, regional NGCC 

generation is limited to a maximum of 

a 5 percent increase from the previous 

year. This phase-in continues in the 

performance rate-setting methodology 

until the full building block 2 level of 

shifting from fossil steam generation to 

NGCC generation is reached. Under this 

approach, building block 2 is 

completely phased into the source 

category calculation of all regions by the 

end of the interim period. 

TABLE 7—BSER MAXIMUM NGCC GENERATION BY REGION AND YEAR (TWh) 

Region 

NGCC generation (TWh) 

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 Interconnection ....................................... 988 735 896 941 988 988 988 988 988 988 988 

Western Interconnection ...................................... 306 198 242 254 267 280 294 306 306 306 306 

Texas Interconnection .......................................... 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64799 

662Negotiating Availability Guarantees for Gas 

Turbine Plants, available at: http://www.powereng.com/articles/print/volume-105/issue-3/

features/negotiating-availability-guarantees-for-gasturbine-plants.html. 

663See, 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/volume-115/

issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html. 

664http://www.eia.gov/todayinenergy/

detail.cfm?id=6990. 

665For 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. 

666Net 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 multihour 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). 

667Appendix 1, CO2 Emission Performance Rate 

and Goal Computation Technical Support 

Document for CPP Final Rule. 

3. Basis for Magnitude of Generation 

Shift 

a. Technical feasibility of NGCC units 

to generate at 75% of their capacity. 

In order to estimate the potential 

magnitude of the opportunity to reduce 

power sector CO2 emissions through 

shifting generation among existing 

EGUs, the EPA first examined 

information on the design capabilities 

and availability of NGCC units. 

Availability is defined as the number of 

hours that generators are available to 

generate electricity, and it is typically 

expressed as a percentage of the total 

number of hours in a year. Since the 

value of NGCC capacity is related to 

how much electricity the owner of that 

capacity can generate and sell, units are 

typically designed with very high 

availability ratings. Baseload units have 

annual average availabilities of 

approximately 91%–92%, and peaking 

units are generally available 96% to 

98% of peak hours.662 The EPA also 

examined information on the historical 

availability of NGCC units in practice. 

This examination showed that, although 

most NGCC units have historically been 

operated in intermediate-duty roles for 

economic reasons, they are technically 

capable of operating in baseload roles at 

much higher annual utilization rates. 

Average annual availability (that is, the 

percentage of annual hours when an 

EGU is not in a forced or maintenance 

outage) for NGCC units in the U.S. 

generally exceeds 85 percent, and can 

exceed 90 percent for some groups.663

We also researched historical data to 

determine the utilization rates that 

NGCC units have already demonstrated 

their capability to sustain. Over the last 

several years, the utilization patterns of 

fossil fuel-fired units have shifted 

relative to historical dispatch patterns, 

with NGCC units increasing generation 

and many coal-fired EGUs reducing 

generation. In fact, in April 2012, for the 

first time ever the total quantity of 

electricity generated nationwide from 

natural gas was approximately equal to 

the total quantity of electricity generated 

nationwide from coal.664 These changes 

in generation patterns have been driven 

largely by changes over time in the 

relative prices of natural gas and coal. 

Although the relative fuel prices vary by 

location, as do the recent generation 

patterns, this trend holds across broad 

regions of the U.S. In the aggregate, the 

historical data provide ample evidence 

indicating that, on average, existing 

NGCC units can achieve and sustain 

utilization rates higher than their 

historical average utilization rates. 

Utilization of EGUs is often 

considered using the metric of a 

capacity factor, which is the percentage 

of total production potential that an 

electric generating unit achieves in a 

given time period. A capacity factor of 

75 percent thus represents a unit 

producing three-quarters of the 

electricity it could have produced in 

that time had it utilized its entire 

capacity. The EPA received multiple 

comments regarding the proposed use of 

nameplate capacity in calculating the 

potential utilization level of existing 

NGCCs under building block 2. These 

comments stated that net summer 

capacity is a more meaningful and 

reliable metric than nameplate capacity, 

because net capacity best reflects the 

electric output available to serve load. 

The EPA agrees with these comments. 

The quantification of building block 2 as 

well as performance rate and state goal 

calculations in the final rule are all 

based on net summer generating 

capacity. An annual utilization rate of 

75 percent on a net summer basis is 

similar to the proposed rule’s 

consideration of 70 percent utilization 

on a nameplate basis.665

The experience of relatively heavilyused NGCC units provides an additional 

indication of the degree of increase in 

average NGCC unit utilization that is 

technically feasible. 

The EPA reexamined the historical 

NGCC plant utilization rate data 

reported to the EIA, and found that in 

2012 roughly 15 percent of existing 

NGCC plants operated at annual 

utilization rates of 75 percent or higher 

on a net summer basis.666 In effect, 

these plants were providing baseload 

power. In addition to the 15 percent of 

NGCC plants that operated 

approximately at a 75 percent 

utilization rate on an annual basis, some 

NGCC plants operated at even higher 

utilization rates for shorter, but still 

sustained, periods of time in response to 

high cyclical demand. For example, on 

a seasonal basis, a significant number of 

NGCC plants have achieved utilization 

rates greater than 90 percent on a net 

summer basis; during the summer of 

2012 (June through August), about 30 

percent of NGCC plants operated at 

utilization rates of 75 percent or more 

across the entire season. During the 

spring and fall periods when electricity 

demand levels are typically lower, these 

plants were sometimes idled or operated 

at much lower capacity factors. 

Nonetheless, the data clearly 

demonstrate that a substantial number 

of existing NGCC plants have proven the 

ability to sustain 75 percent utilization 

rates for extended periods of time. We 

view this as strong evidence that 

increasing the annual average utilization 

rates of existing NGCC units to 75 

percent on a net summer basis would be 

technically feasible. 

The EPA believes that an annual 

average utilization rate of 75 percent on 

a net summer basis is a conservative 

assessment of what existing NGCC 

plants are capable of sustaining for 

extended periods of time. In 2012, 

roughly 10 percent of existing NGCC 

plants operated at annual utilization 

rates of 80 percent or higher on a net 

summer basis. While the EPA believes 

this level is also technically feasible on 

average for the existing NGCC fleet, the 

EPA is quantifying building block 2 

assuming an NGCC utilization level of 

75% on a net summer basis in order to 

offer sources additional compliance 

flexibility, given that the extent to 

which they realize a utilization level 

beyond 75 percent will reduce their 

need to rely on other emission reduction 

measures or building blocks. 

b. Historical generation shifts to 

NGCC generation. 

In 2012, total electric generation from 

existing NGCC units was 966 TWh.667

After the application of the building 

block 2 potential (increasing NGCC 

utilization up to a 75 percent capacity 

factor on a net summer basis, including 

generation from NGCC units that were 

under construction), the total generation 


tkelley on DSK3SPTVN1PROD with BOOK 2
64800 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

668Appendix 1, CO2 Emission Performance Rate 

and Goal Computation Technical Support 

Document for CPP Final Rule. 

669See section VIII for further discussion of 

electric reliability planning. 

670EIA, 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). 671EIA, Electric Power Monthly, February, 2014. 

Table 6.7.A. 672See, e.g., EIA, Natural Gas Pipeline Additions 

in 2011, Today in Energy, available at http://

www.eia.gov/todayinenergy/detail.cfm?id=5050; 

INGAA Foundation, Pipeline and Storage 

Infrastructure Requirements for a 30 Tcf Market 

(2004 update), available at http://www.ingaa.org/

Foundation/Foundation-Reports/Studies/

FoundationReports/45.aspx; INGAA Foundation, 

North American Midstream Infrastructure Through 

2035—A Secure Energy Future Report (2011), 

available at http://www.ingaa.org/

File.aspx?id=14911. 

673Pipeline 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. 

674For 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. 

from these existing sources is assumed 

to be 1,498 TWh.668

The EPA believes that producing this 

quantity of generation from this set of 

NGCC units is feasible. To put this level 

of generation into context, NGCC 

generation increased by approximately 

439 TWh (an 83 percent increase) 

between 2005 and 2012. The EPA 

calculates that assumed NGCC 

generation in 2022 through the 

quantification of building block 2 

potential is approximately 44 percent 

higher than 2014 levels. This reflects a 

smaller growth rate in potential NGCC 

generation between 2015 and 2022 than 

has been observed in practice from 2005 

to 2012, a time period of the same 

duration. 

c. Reliability. 

We also expect that an increase in 

NGCC generation of this amount would 

not impair power system reliability. 

Sources can achieve increases in 

utilization of existing NGCCs that 

displace generation from steam sources 

without impacting reliability because 

this shift in average annual utilization 

across existing EGUs does not inhibit 

the 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 reliabilityrelevant operations while achieving 

emission reductions through a variety of 

measures.669

d. Natural gas infrastructure. 

The EPA also examined the technical 

capability of the natural gas supply and 

delivery system to provide increased 

quantities of natural gas and the 

capability of the electricity transmission 

system to accommodate shifting 

generation patterns. For several reasons, 

we conclude that these systems would 

be capable of supporting the degree of 

increased NGCC utilization potential in 

building block 2. First, the natural gas 

pipeline system is already supporting 

national average NGCC utilization rates 

of 60 percent or higher during peak 

hours, which are the hours when 

constraints on pipelines or electricity 

transmission networks are most likely to 

arise. NGCC unit utilization rates during 

the range of peak daytime hours from 10 

a.m. to 9 p.m. are typically 15 to 20 

percentage points above their average 

utilization rates (which have recently 

been in the range of 40 to 50 percent).670

Fleet-wide combined-cycle average 

monthly utilization rates have reached 

65 percent,671 showing that the pipeline 

system can currently support these rates 

for an extended period. If the current 

pipeline and transmission systems 

allow these utilization rates to be 

achieved in peak hours and for 

extended periods, it is reasonable to 

expect that similar utilization rates 

should also be possible in other hours 

when constraints are typically less 

severe, and be reliably sustained for 

other months of the year. Furthermore, 

the NGCC utilization increase assumed 

in building block 2 could occur without 

a significant impact on peak demand for 

natural gas, including winter demand 

(when the power sector’s demand for 

natural gas competes with other sectors’ 

demands for natural gas), since 

increasing annual utilization of NGCCs 

could focus on non-peak periods when 

NGCC capacity factors are currently 

low. 

The second consideration supporting 

a conclusion regarding the adequacy of 

the gas supply infrastructure is that 

pipeline and transmission planners 

have repeatedly demonstrated the 

ability to methodically relieve 

bottlenecks and expand capacity.672

Natural gas pipeline capacity has 

regularly been added in response to 

increased gas demand and supply, such 

as the addition of large amounts of new 

NGCC capacity from 2001 to 2003, or 

the delivery to market of 

unconventional gas supplies since 2008. 

These pipeline capacity increases have 

added significant deliverability to the 

natural gas pipeline network to meet the 

potential demands from increased use of 

existing NGCC units. Over a longer time 

period, much more significant pipeline 

expansion is possible. In previous 

studies, when the pipeline system was 

expected to face very large demands for 

natural gas use by electric utilities, the 

pipeline industry projected that 

increases of up to 30 percent in total 

deliverability out of the pipeline system 

would be possible.673 There have been 

notable pipeline capacity expansions 

over the past five years, and substantial 

additional pipeline expansions are 

currently under construction.674

Further, the phasing in of building block 

2’s potential in the determination of the 

BSER; the flexible nature of multi-year 

compliance with the ultimate emission 

reduction requirements of the rule; and 

the seven years between finalization of 

this rule and the first year of compliance 

provide time for infrastructure 

improvements to occur should they 

prove necessary in some locations. 

Combining these factors of currently 

observed average monthly NGCC 

utilization rates of up to 65 percent, the 

flexibility of the emission guidelines, 

the rates of historical growth, and the 

availability of time to address any 

existing pipeline infrastructure 

limitations, it is reasonable to conclude 

that the natural gas pipeline system can 

reliably deliver sufficient natural gas 

supplies to allow NGCC utilization to 

increase up to an average annual 

capacity factor of 75 percent on a net 

summer basis. 

e. Natural gas production. 

We recognize that an increase in 

NGCC utilization rates at existing units 

corresponds with an associated increase 

in natural gas production, consistent 

with the current trends in the natural 

gas industry. The EPA expects the 

growth in NGCC generation assumed for 

building block 2 to be feasible and 

consistent with the production potential 

of domestic natural gas supplies. 

Increases in the natural gas resource 

base have led to fundamental changes in 

the outlook for natural gas. There is 

general agreement that recoverable 

natural gas resources will be 

substantially higher for the foreseeable 

future than previously anticipated, 

exerting downward pressure on natural 

gas prices. According to EIA, proven 

natural gas reserves have doubled 

between 2000 and 2012. Domestic dry 

gas production has increased by 25 

percent over that same timeframe (from 

19.2 TCF in 2000 to 24.0 TCF in 2012). 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64801 

675See Greenhouse Gas Mitigation Measures TSD 

for a discussion of regional NGCC capacity factors. 

676According 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. 

EIA’s Annual Energy Outlook Reference 

Case for 2015 projects that production 

will further increase to 29.5 TCF by 

2022 and 33 TCF by 2030, as a result of 

increased supplies and favorable market 

conditions. In the AEO 2015 high oil 

and gas resource case, production is 

projected to increase to 42.7 TCF in 

2030. For comparison, building block 2 

assumes NGCC generation growth of 235 

TWh from 2012 to reach the level 

assumed for 2022, and that NGCC 

generation growth would result in 

increased gas consumption of less than 

2 TCF for the electricity sector, which 

is less than EIA’s projected increase in 

natural gas production of 5.5 TCF from 

2012 to 2022. 

The EPA has also assessed the ability 

of the electricity and natural gas 

industries to achieve the potential 

quantified for building block 2 using the 

Integrated Planning Model (IPM). IPM is 

a multi-regional, dynamic, deterministic 

linear programming model of the U.S. 

electric power sector that the EPA has 

used for over two decades to evaluate 

the economic and emission impacts of 

prospective environmental policies. To 

inform its projections of least-cost 

capacity expansion and electricity 

dispatch, IPM incorporates 

representations of constraints related to 

fuel supply, bulk power transmission 

capacity, and unit availability. The 

model includes a detailed 

representation of the natural gas 

pipeline network and the capability to 

project economic expansion of that 

network based on pipeline load factors. 

At the EGU level, IPM includes detailed 

representations of key operational 

limitations such as turn-down 

constraints, which are designed to 

account for the cycling capabilities of 

EGUs to ensure that the model properly 

reflects the distinct operating 

characteristics of peaking, cycling, and 

base load units. 

As described in more detail below, 

the EPA used IPM to assess the costs of 

increasing generation from existing 

NGCC capacity. IPM was able to meet 

average NGCC utilization rates of 75 

percent on a net summer basis, while 

observing the market, technical, and 

regulatory constraints represented in the 

model. This modeling also demonstrates 

the ability of domestic natural gas 

supplies to increase their production 

levels, and deliver that supply through 

the pipeline network, to support the 

level of NGCC generation quantified in 

building block 2. Such a result is 

consistent with the EPA’s determination 

that increasing the average utilization 

rate of existing NGCC units to 75 

percent would be technically feasible. 

f. Transmission planning and 

construction. 

Achieving the generation shift 

quantified in building block 2 would 

not impose significant additional 

burden on the transmission planning 

process and does not necessitate major 

construction projects. Two 

considerations are important for this 

conclusion: 

First, building block 2 applies only to 

increases in generation at existing NGCC 

facilities and does not contemplate any 

connection of new capacity to the bulk 

power grid. Second, regional grids are 

already supporting operation of the 

NGCC units for sustained periods of 

time at the capacity factors quantified in 

building block 2.675 Although some 

upgrades to the grid (including 

potential, but modest, expansions of 

transmission capacity) may be necessary 

to support the extension of the time that 

these capacity factors are sustained over 

the course of the annual time period on 

which building block 2 is based, such 

upgrades are part of the normal 

planning process around the increased 

use of existing facilities. In fact, the 

electric transmission system is currently 

undergoing substantial expansion.676

Consequently, EPA does not believe that 

achieving the generation shift potential 

in building block 2 would necessitate 

any significant additional requirements 

for transmission planning and 

construction beyond those already being 

addressed at routine intervals by the 

power sector. Furthermore, the phasing 

in of building block 2’s potential in the 

determination of the BSER; the flexible 

nature of multi-year compliance with 

the ultimate emission reduction 

requirements of the rule; and the seven 

years between finalization of this rule 

and the first year of compliance all 

provide time for infrastructure 

improvements to occur should they 

prove necessary in some locations. 

g. Regulatory flexibility. 

The final consideration supporting 

our view that natural gas and electricity 

system infrastructure would be capable 

of supporting increased NGCC unit 

utilization rates at a maximum of 75% 

on a net summer basis is the substantial 

unit-level compliance flexibility of the 

emission guidelines. The final rule does 

not require any particular NGCC unit to 

achieve any particular utilization rate in 

any specific hour or year. Thus, even if 

isolated natural gas or electricity system 

constraints were to limit NGCC unit 

utilization rates in certain locations in 

certain hours, this would not prevent an 

increase in NGCC generation overall 

across a state or broader region and 

across all hours on the order assumed in 

the generation shift potential quantified 

for building block 2. 

4. Cost 

Having established the technical 

feasibility and quantification of the 

potential to replace incremental 

generation at higher-emitting EGUs with 

generation at NGCC facilities as a CO2

emissions reduction strategy, we next 

turn to the question of cost. The cost of 

the power sector CO2 emission 

reductions that can be achieved through 

shifting generation among existing fossil 

fuel-fired EGUs depends on the relative 

variable costs of electricity production 

at EGUs with different degrees of carbon 

intensity. These variable costs are 

driven by the EGUs’ respective fuel 

costs and by the efficiencies with which 

they can convert fuel to electricity (i.e., 

their heat rates). Historically, natural gas 

has had a higher cost per unit of energy 

content (e.g., MMBtu) than coal in most 

locations, but 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 

methods 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 


tkelley on DSK3SPTVN1PROD with BOOK 2
64802 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

677According 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. 

across all existing fossil fuel-fired 

sources. The EPA conducted such 

scenarios to address average utilization 

rates of 70 percent, 75 percent and 80 

percent on a net basis, allowing for 

shifting of fossil generation between 

existing units within the regions 

described above. This scenario 

identifies a generation pattern that 

would meet electricity demand at the 

lowest total cost, subject to all other 

specified operating and bulk power 

transfer constraints for the scenario, 

including the specified average NGCC 

unit utilization rate. 

The costs of the various scenarios 

were evaluated by comparing the total 

costs and emissions from each scenario 

to the costs and emissions from a base 

case scenario. For the scenario reflecting 

a 75 percent NGCC utilization rate on a 

net basis with regional fossil generation 

shifting, comparison to the base case 

indicates that the average cost of the 

CO2 reductions achieved over the 2022– 

2030 period was $24 per short ton of 

CO2. We view these estimated costs as 

reasonable and therefore as supporting 

the use of a 75 percent net utilization 

rate target for purposes of quantifying 

the emission reductions achievable at a 

reasonable cost through the application 

of building block 2 in the BSER. 

We also conclude from these analyses 

that potential impacts to fuel prices and 

electricity prices from achieving the 

extent of fossil generation shifting 

quantified for this building block are 

reasonably within the bounds of power 

sector experience. For example, in the 

75 percent NGCC unit utilization rate 

scenario where generation shifting is 

limited to regional boundaries, the 

delivered natural gas price was 

projected to increase by an average of 7 

percent over the 2022–2030 period, 

which is well within the range of 

historical natural gas price 

variability.677 Projected wholesale 

electricity price increases over the same 

period were less than 4 percent, which 

similarly is well within the range of 

historical electric price variability. 

These projected impacts on prices were 

captured in the emission reduction costs 

of these scenarios already described 

above, which are reasonable and 

support use of a 75 percent NGCC 

utilization rate target for purposes of 

quantifying the emission reductions 

achievable through application of the 

BSER. 

However, we also note that the costs 

(and their incorporated price impacts) 

just described are higher than we would 

expect to actually occur in real-world 

compliance with the final rule’s 

compliance requirements for the 

following reasons. First, this analysis 

does not capture the building block 2 

phase-in, which assumes an average 

utilization rate over the interim period 

of less than 75 percent in all three 

interconnections. Second, the analysis 

overstates the extent to which building 

block 2 is ultimately reflected in the 

source category performance rates. 

While the performance rate computation 

procedure assumes a maximum NGCC 

utilization rate of 75 percent on a net 

summer basis, the Eastern 

Interconnection’s realization of this 

level of NGCC utilization yields higher 

source category performance rates for 

steam than what would have been 

calculated for units in the Western 

Interconnection and Texas 

Interconnection if they realized that 

maximum NGCC utilization rate in 

conjunction with the other building 

blocks. In other words, there is 

substantial building block 2 potential in 

the Western Interconnection and Texas 

Interconnection that is not actually 

captured in the source category 

performance rates that are ultimately 

assigned to steam through this rate- and 

goal-setting approach (where the 

performance rates are ultimately 

determined by the BSER region with the 

highest rate outcome in the calculation). 

Therefore, the building block 2 analysis 

overstates the cost of this component of 

BSER to the extent that it assumes 

achievement of this generation shift 

potential that is not reflected in the 

source category performance rates 

ultimately determined. Third, as a 

practical matter, sources will be able to 

achieve additional emission reductions 

through other measures that may prove 

to be less costly than generation shifting 

and could substitute for the reductions 

and costs considered here. These 

building block 2 analyses were focused 

on evaluating the potential impacts of 

fossil generation shifting in isolation, 

and as a result, they do not consider 

states’ and sources’ flexibility to choose 

among alternative CO2 reduction 

strategies that could offer lower-cost 

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, cost-effective, 

and adequately demonstrated building 

block for BSER. 

For further information on the 

analysis discussed in this section, see 

Chapter 3 of the GHG Mitigation 

Measures TSD for the CPP Final Rule. 

5. Major Comments and Responses 

The EPA received numerous 

comments regarding building block 2. 

Many of these comments provided 

helpful information and insights and 

have resulted in improvements to the 

rule. This section summarizes some of 

these comments, and the remainder of 

the comments are responded to in the 

Response to Comment document, 

available in the docket. 

The EPA received comment regarding 

the potential for an increase in upstream 

methane emissions from increased 

utilization of natural gas. Our analysis 

found that the net upstream methane 

emissions from natural gas systems and 

coal mines and CO2 emissions from 

flaring of methane will likely decrease 

under the Clean Power Plan. 

Furthermore, the changes in upstream 

methane emissions are small relative to 

the changes in direct emissions from 

power plants. The technical details 

supporting this analysis can be found in 

the Regulatory Impact Analysis. 

Commenters also expressed concern 

that neither a utility nor any state 

agency controls dispatch in most states. 

The EPA believes these comments fail to 

adequately appreciate that the utilities 

do control the dispatch of units that 

they own and/or operate, either by being 

the actual dispatch agent in many cases 

where there is no RTO or ISO that 

schedules the dispatch, or by the choice 

of units and bids they offer into an 

organized electricity market operated by 

an RTO or ISO. These entities currently 

control the dispatch of their units while 

respecting all existing requirements 

from environmental rules. This final 

rule does not change these current 

circumstances and makes clear that it is 

the EGU that is responsible for meeting 

the requirements in the state plan; the 

state is responsible for the development 

of that plan, but the state does not need 

to control the dispatch. 

Other comments object to the use of 

a single capacity factor for all existing 

NGCCs to quantify building block 2 

potential on the grounds that not all 

units may be able to achieve this 

utilization level, and that some units 

may be designed for cycling and so may 

need upgrades to sustain such 

utilization. The EPA disagrees with 

these comments. The 75 percent 

capacity factor establishes a regional 

potential for generation from existing 

NGCC capacity, and it does not establish 

any individual unit requirements. 

Some comments argue that generation 

limits in permits for some existing 

NGCC units will limit the amount by 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64803 

678Nearly all U.S. hydroelectric capacity was 

built before the mid-1970s. U.S. DOE. History of 

Hydropower. Accessed March 2015. Available at: 

http://energy.gov/eere/water/history-hydropower. 

679U.S. DOE Office of Management, Timeline of 

Events: 1971–1980. Accessed March 2015. 

Available at: http://energy.gov/management/officemanagement/operational-management/history/doehistory-timeline/timeline-events-1. 

680 ‘‘Restructuring or Deregulation?’’ Smithsonian 

Museum of American History. Accessed March 

2015. Available at: http://americanhistory.si.edu/

powering/dereg/dereg1.htm. 

681Energy Information Administration, Annual 

Energy Outlook 2014 with Projections to 2040, at 

LR–5 (2014). 

682 IPCC, Renewable Energy Sources and Climate 

Change Mitigation, 2012. Accessed March 2015. 

Available at: http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

683American Wind Energy Association. AWEA 

Comments on EPA’s Proposed Carbon Pollution 

Emission Guidelines for Existing Stationary Sources 

and Supplemental Proposed Rule. p. 107. 

684Energy Information Administration, Monthly 

Energy Review, May 2015, Table 7.2b. Available at: 

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

sec7_6.pdf. 

685Non-hydro RE capacity for the total electric 

power industry was more than 16,000 megawatts in 

1998. Energy Information Administration, 1990– 

2013 Existing Nameplate and Net Summer Capacity 

by Energy Source Producer Type and State (EIA– 

860). Available at: http://www.eia.gov/electricity/

data/state/. 

686Energy Information Administration, Monthly 

Energy Review, May 2015, Table 7.2b. Available at: 

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

sec7_6.pdf. 

which these units can increase their 

generation and thereby limit the 

feasibility of building block 2. The EPA 

disagrees with these comments. 

Although permit limits can constrain 

the ability of individual units to operate 

above certain levels, building block 2 

was developed conservatively, with 

units operating on average at a level 

below the maximum levels at which 

some units have demonstrated the 

capability to operate. No individual unit 

is required to achieve the average 

generation levels used to quantify 

building block 2. Further, permit limits 

at individual units can be considered 

when state plans are developed. There 

are many flexibilities in the final rule, 

including the opportunity to establish 

standards of performance that 

incorporate emissions trading or 

develop plans that will respect any 

existing permit limits at individual 

units. 

The EPA also received comments 

asserting that increasing generation from 

new renewables would require 

increased use of natural gas capacity for 

back-up and ramping, and therefore it is 

not possible for NGCC units to run at 

BSER utilization rates and also be 

available to support the additional 

variable renewable generation resulting 

from building block 3. The EPA 

disagrees with this comment. The 75% 

net summer utilization rates defined by 

building block 2 is a conservative 

assessment and applied on an annual 

average basis. It is therefore possible for 

these existing units to both operate at 

higher annual utilization rates, and also 

to operate at higher rates during limited 

periods and still maintain a 75% net 

summer average annual utilization rate. 

While variable renewable generation 

does require additional load following 

and ramping resources and unit cycling, 

these requirements are generally a small 

part of the overall ramping costs of the 

system (see NREL, Relevant Studies for 

NERC’s Analysis of EPA’s Clean Power 

Plan 111(d) Compliance). Additionally, 

while existing NGCC units are an 

efficient source of ramping to support 

variable renewables, other units running 

in an intermediate mode can also 

provide load following and ramping. 

E. Building Block 3—New Zero-Emitting 

Renewable Generating Capacity 

The third element of the foundation 

for the EPA’s BSER determination for 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs entails an analysis 

of the extent to which generation at the 

affected EGUs can be replaced by using 

an expanded amount of zero-emitting 

renewable electricity (RE) generating 

capacity to produce replacement 

generation. 

In this section we address first the 

history of and then trends in RE 

development, as well as the importance 

of expanding the use of RE. Next we 

discuss the ability of affected EGUs to 

access generation from new RE 

generating capacity, followed by a 

discussion of renewable energy 

certificate (REC) markets. We then 

describe the quantification of the 

amount of generation from new RE 

generating capacity achievable through 

building block 3, including key 

comments, changes made from the 

proposal, the method by which RE 

target generation levels are quantified, 

and the magnitude and timing of 

increases in RE generation associated 

with this building block. Next, we 

discuss the feasibility of implementing 

the identified incremental amounts of 

RE generation. Finally, we address the 

costs associated with those increases in 

RE generation. 

1. History of RE Development 

RE generating technologies are a wellestablished part of the utility power 

sector. These technologies generate 

electricity from renewable resources, 

such as wind, sun and water. While RE 

has been used to generate electricity for 

over a century, the push to 

commercialize RE more broadly began 

in the 1970s.678 Following a series of 

energy crises, new federal organizations 

and initiatives were established to 

coordinate energy policy and promote 

energy self-sufficiency and security, 

including solar energy legislation, the 

Public Utility Regulatory Policies Act of 

1978 (PURPA) and the 1980 Energy 

Security Act.679

PURPA was a key step in stimulating 

RE development. By requiring utilities 

to purchase generation from qualifying 

facilities (i.e., certain CHP and RE 

generators) at avoided costs, PURPA 

opened electricity markets to more RE 

generation and gave rise to non-utility 

generators that were willing to try new 

RE technologies.680 In addition, since 

1992, federal tax policy has provided 

important financial support via tax 

credits for the production of RE and 

investments in RE. 

States have also taken a significant 

lead in requiring the development of RE 

resources. In particular, a number of 

states have adopted renewable portfolio 

standards (RPS), which are regulatory 

mandates to increase production of RE. 

As of 2013, 29 states and the District of 

Columbia had enforceable RPS or 

similar laws.681 These RPS requirements 

continue to drive robust near-term 

growth of non-hydropower RE. 

2. Trends in RE Development 

Today, RE is tightly integrated with 

the utility power sector in multiple 

ways: States have set RE targets for 

electrical load serving entities; utilities 

themselves are diversifying their 

portfolios by contracting with RE 

generators; and new RE generators are 

being developed to provide more 

electrical power grid support services 

beyond just energy (e.g., modern 

electronics allow wind turbines to 

provide voltage and reactive power 

control at all times).682 683

Use of RE continues to grow rapidly 

in the U.S. In 2013, electricity generated 

from RE technologies, including 

conventional hydropower, represented 

12 percent of total U.S. electricity, up 

from 8 percent in 2005.684 In 2013, U.S. 

non-hydro RE capacity for the total 

electric power industry exceeded 80,000 

megawatts, reflecting a fivefold increase 

in just 15 years.685 In particular, there 

has been substantial growth in the wind 

and solar photovoltaic (PV) markets in 

the past decade. Since 2009, U.S. wind 

generation has tripled and solar 

generation has grown twentyfold.686

The global market for RE is projected 

to grow to $460 billion per year by 


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687 ‘‘Global Renewable Energy Market Outlook.’’ 

Bloomberg New Energy Finance, November 16, 

2011. Available at http://bnef.com/WhitePapers/

download/53. 

688Lopez et al., NREL, ‘‘U.S. Renewable Energy 

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

2012). Available at http://www.nrel.gov/docs/

fy12osti/51946.pdf. 

689Energy Information Administration, Annual 

Energy Outlook 2015 with Projections to 2040 

(2015), p. 25. Available at http://www.eia.gov/

forecasts/aeo/pdf/0382(2015).pdf. 

690Energy Information Administration, Annual 

Energy Outlook 2015 with Projections to 2040 

(2015), p. ES–6–7. Available at http://www.eia.gov/ 

forecasts/aeo/pdf/0382(2015).pdf. 

691Lazard, Levelized Cost of Energy AnalysisVersion 8.0, September 2014, p. 9, Available at: 

http://www.lazard.com/media/1777/levelized_cost_

of_energy_-_version_80.pdf. 

692 ‘‘2013 Wind Technologies Market Report,’’ 

LBNL, August 2014. Available at http://emp.lbl.gov/ 

sites/all/files/2013_Wind_Technologies_Market_

Report_Final3.pdf. 

693 ‘‘2013 Cost of Wind Energy Review,’’ NREL, 

Feb 2015. Available at: http://www.nrel.gov/docs/

fy15osti/63267.pdf. 

694 ‘‘Tracking the Sun VII’’ LBNL, Sept 2014. 

Available at: http://emp.lbl.gov/publications/

tracking-sun-vii-historical-summary-installed-pricephotovoltaics-united-states-1998-20. 

695 ‘‘Photovoltaic System Pricing Trends,’’ NREL, 

22 Sept 2014. Available at: http://www.nrel.gov/

docs/fy14osti/62558.pdf. 

696 ‘‘Revolution Now—The Future Arrives for 

Four Clean Energy Technologies—2014 Update,’’ 

DOE, Oct 2014. Available at: http://energy.gov/sites/ 

prod/files/2014/10/f18/revolution_now_updated_

charts_and_text_october_2014_1.pdf. 

697 ‘‘Utility-Scale Solar 2013,’’ LBNL, Sept 2014. 

Available at: http://emp.lbl.gov/publications/utilityscale-solar-2013-empirical-analysis-project-costperformance-and-pricing-trends. 

698U.S. Energy Information Administration 

Annual Energy Review, 2011. Accessed March 

2015. Available at: http://www.eia.gov/totalenergy/ 

data/monthly/pdf/flow/primary_energy.pdf. 

699California S.B. 2 (1X), 2011. Accessed March 

2015. Available at: http://www.leginfo.ca.gov/pub/

11-12/bill/sen/sb_0001-0050/sbx1_2_bill_

20110412_chaptered.pdf. 

700 IPCC, Renewable Energy Sources and Climate 

Change Mitigation, 2012. Accessed March 2015. 

Available at: http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

701EPA, Water Resource Use. Accessed on March 

2015. Available at: http://www.epa.gov/clean

energy/energy-and-you/affect/water-resource.html. 

702Refer to the GHG Mitigation Measures TSD for 

additional information on RE ownership and colocation. 

2030.687 RE growth is further spurred by 

the significant amount of existing 

natural resources that can support RE 

production in the U.S.688 In the Energy 

Information Administration’s Annual 

Energy Outlook 2015, RE generation 

grows substantially from 2013 to 2040 

in the reference case and all alternative 

cases.689 In the reference case, RE 

generation increases by more than 70 

percent from 2013 to 2040 and accounts 

for over one-third of new generation 

capacity.690

The recent and projected growth of RE 

is in part a reflection of its increasing 

economic competitiveness. Numerous 

studies have tracked capital cost 

reductions and performance 

improvements for RE, particularly for 

solar and wind. For instance, Lazard’s 

analysis of wind and utility-scale solar 

PV levelized costs of energy (LCOE), on 

an unsubsidized basis, over the last five 

years found the average percentage 

decrease of high and low of LCOE 

ranges were 58 percent and 78 percent, 

respectively.691 Analyses of wind’s 

competitiveness found falling wind 

turbine LCOE while the wind industry 

developed projects at lower wind speed 

sites using new turbine designs (e.g., 

increased turbine hub heights and rotor 

diameters). Performance improvements 

have come from novel deployments of 

new turbines designed for lower quality 

wind sites that are deployed at higher 

quality wind sites, which have resulted 

in capacity factor increases for these 

locations.692 693 For utility-scale solar, 

cost and performance have also 

improved significantly. Analysis has 

shown that the installed price of solar 

photovoltaics (PV) systems, prior to any 

incentives, has declined substantially 

since 1998. Capacity-weighted average 

prices of solar PV in utility-scale 

deployments were 40 percent lower in 

2013 than five years earlier.694 695

Initially, price declines were partially 

driven by oversupply and 

manufacturers’ thin margins, but, in 

2014, prices have remained low due to 

reductions in manufacturing costs.696

The capacity factors of new utility-scale 

installations have increased as systems 

are optimized to maximize energy 

production. For example, a growing 

number of utility-scale PV systems are 

increasing the direct current capacity of 

the solar array relative to the alternating 

current rating of the array’s inverter to 

increase energy production and improve 

project economics.697 The cost and 

performance improvements for wind 

and solar are driven by increased scale 

of production, improved technologies, 

and advancements in system 

deployments. 

3. Importance of Increasing Use of RE 

Currently, the utility power sector 

accounts for 40 percent of total annual 

energy consumption in the U.S.698

Introducing more zero-emitting RE 

generation over the long term could 

significantly reduce CO2 emissions, as 

production of RE predominantly 

replaces fossil fuel-fired generation and 

thereby avoids the emissions from that 

replaced generation. 

A number of studies and recent policy 

developments have acknowledged RE as 

an important means of achieving CO2

reductions. California cited the 

reduction of CO2 emissions from 

electrical generations as one of the 

reasons for increasing its RE target from 

20 percent to 33 percent by 2020 (and 

potentially 50 percent by 2030).699 A 

recent IPCC report also concluded that 

RE has large potential to mitigate CO2

emissions.700

Increased use of RE provides 

numerous benefits in addition to lower 

CO2 emissions. RE typically consumes 

less water than fossil fuel-fired EGUs. 

Wind power and solar PV systems do 

not require the use of any water to 

generate electricity; water is only 

needed for cleaning to ensure efficient 

operation. In contrast, utility boilers, in 

particular, require large quantities of 

water for steam generation and 

cooling.701

Increasing RE use will also continue 

to lower other air pollutants (e.g., fine 

particles, ground-level ozone, etc.). In 

addition, the RIA notes that increasing 

RE will diversify energy supply, hedge 

against fossil fuel price increases and 

create economic development and jobs 

in manufacturing, installation, and other 

sectors of the economy. 

4. Access to RE by Owners of Affected 

EGUs 

The ability of affected EGUs to colocate or obtain incremental RE to 

reduce CO2 emissions is welldemonstrated, whether it is through 

direct ownership, bilateral contracts, or 

procurement of the environmental 

attributes associated with RE 

generation.702 Consequently, the EPA 

believes that an increase in RE is a 

proven way to reduce CO2 emissions at 

affected EGUs of all types at a 

reasonable cost. 

Owners and operators of affected 

EGUs across the U.S. already have 

substantial opportunities to procure RE 

regardless of their organizational 

structure and/or business model. In 

many parts of the country, EGUs are 

owned and operated by vertically 

integrated utilities. These utilities can 

be investor-owned utilities that operate 

under traditional electricity regulation, 

municipal utilities (munis), or electric 

cooperatives (co-ops). These utilities 

have significant control over the types 

of generating capacity they develop or 

acquire, and over the electricity mix 

used to meet demand within their 

service territories. 

Even when EGU owners participating 

in organized markets do not directly 

determine dispatch among energy 

sources, such EGU owners make 


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703SNL Energy. Data used with permission. 

Accessed on June 9, 2015. 

704 Ibid. 

705SNL Energy. Data used with permission. 

Accessed on June 9, 2015. 

706 eGRID, EPA. 2012 Unit-Level Data Using the 

eGRID Methodology. 

707American Wind Energy Association. AWEA 

Comments on EPA’s Proposed Carbon Pollution 

Emission Guidelines for Existing Stationary Sources 

and Supplemental Proposed Rule. pp. 88–91. 

708Solar 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. 

709American Wind Energy Association. U.S. 

Wind Industry Annual Market Report (2014 data). 

Accessed July 2015. Available at http://www.awea.

org/AnnualMarketReport.aspx?ItemNumber=7422&

RDtoken=64560&userID=. The ten largest electric 

utilities with wind power capacity on the system 

(owner or under contract) includes: Xcel Energy; 

Berkshire Hathaway Energy; Southern California 

Edison; American Electric Power; Pacific Gas & 

Electric; Tennessee Valley Authority; San Diego Gas 

& Electric; CPS Energy; Los Angeles Department of 

Water & Power; and Alliant Energy. 

710See memo entitled ‘‘Review of Electric Utility 

Integrated Resource Plans’’ (May 7, 2015). 

711 Dominion North Carolina Power’s and 

Dominion Virginia Power’s Report of Its Integrated 

Resource Plan, August 2014. Available at: https:// 

www.dom.com/library/domcom/pdfs/corporate/

integrated-resource-planning/nc-irp-2014.pdf. 

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 zero-emitting 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.703

Some of the largest owners of affected 

EGUs also owned RE (see Table 8). For 

example, NRG Energy, Inc. owns more 

than 3,000 megawatts of RE capacity, 

over 20 percent of which (nearly 800 

megawatts) is solar, and almost 80 

percent of which (over 2,500 megawatts) 

is wind. Duke Energy Corporation owns 

175 megawatts of solar and over 1,500 

megawatts of wind. NextEra Energy, 

Inc.’s share of RE capacity approaches 

40 percent of their total affected EGU 

capacity.704 Table 8 lists a sampling of 

affected EGUs that have large amounts 

of fossil fuel-fired capacity and RE 

capacity: 

TABLE 8—SAMPLE OF OWNERS OF AFFECTED EGUS AND RE CAPACITY 705 706

Ultimate parent 

Affected EGU 

capacity 

(MW) 

Renewable 

capacity 

(MW) 

NRG Energy, Inc ..................................................................................................................................................... 48,787 3,149 

Duke Energy Corporation ........................................................................................................................................ 39,028 5,526 

Southern Company .................................................................................................................................................. 37,168 3,245 

American Electric Power Company, Inc .................................................................................................................. 34,940 1,142 

NextEra Energy, Inc ................................................................................................................................................ 29,471 11,626 

Calpine Corporation ................................................................................................................................................. 23,878 1,509 

Tennessee Valley Authority ..................................................................................................................................... 21,717 5,427 

Berkshire Hathaway Inc ........................................................................................................................................... 18,899 6,650 

FirstEnergy Corp. ..................................................................................................................................................... 16,175 1,371 

Exelon Corporation .................................................................................................................................................. 10,283 3,361 

Nebraska Public Power District ............................................................................................................................... 2,003 90 

Basin Electric Power Cooperative ........................................................................................................................... 1,526 275 

American Municipal Power, Inc ............................................................................................................................... 1,112 53 

Sacramento Municipal Utility District ....................................................................................................................... 925 834 

Golden Spread Electric Cooperative, Inc ................................................................................................................ 521 78 

Large vertically integrated utilities 

generally have multiple options for 

investing in RE, including building their 

own RE capacity or procuring RE under 

a long-term power purchase agreement. 

Municipal utilities and rural 

cooperatives that own generating asset 

portfolios, particularly generation and 

transmission cooperatives and larger 

municipal utilities, have also used RE to 

reduce carbon emissions. Large 

generation and transmission 

cooperatives also purchase significant 

quantities of RE for their members. 

Federal power authorities own or 

contract for significant amounts of 

RE.707 708

The list of ten electric utilities with 

the largest amounts of wind power 

capacity on the system (owned or under 

contract) includes a variety of affected 

EGU organizational structures, 

including vertically integrated investorowned utilities, municipal utilities, and 

federal power authorities. Xcel Energy 

and Berkshire Hathaway Energy rank 

first and second with 5,736 megawatts 

and 4,992 megawatts of wind capacity, 

respectively. Tennessee Valley 

Authority, a federal power authority, 

had 1,572 megawatts and CPS Energy, a 

public utility, had 1,059 megawatts of 

wind power capacity.709 Basin Electric 

Power Cooperative had 716 megawatts 

and was the top ranked cooperative 

utility, but is not on the top ten utilities 

with wind power capacity list. 

Many affected EGUs are already 

planning on deploying significant 

amounts of RE according to their 

integrated resource plans (IRPs). Electric 

utilities use IRPs to plan operations and 

investments over long time horizons. 

These plans typically cover 10 to 20 

years and are mandated by public utility 

commissions (PUCs). A recent study of 

IRPs, included in the docket for this 

rulemaking, shows this trend.710 For 

instance, Dominion plans for over 800 

megawatts of wind and solar in their 

2015 to 2029 planning period.711 Duke 

Energy Carolinas’ IRP has no plans for 

new coal, but describes plans for 

roughly 1,250 megawatts of additional 

RE by 2021, and approximately 2,150 

megawatts by 2029. A significant 


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712 Duke Energy Carolinas’ 2014 Integrated 

Resource Plan, September 2014. Available at: http:// 

starw1.ncuc.net/NCUC/ViewFile.aspx?Id=

c3c5cbb5-51f2-423a-9dfc-a43ec559d307. 

713 Integrated Resource Plan Update, October 

2014. Available at: https://www.ameren.com/

missouri/environment/renewables/amerenmissouri-irp. 

714NRG, ‘‘NRG Energy Sets Long-Term 

Sustainability Goals at Groundbreaking of ‘UltraGreen’ New Headquarters’’ (Nov. 20, 2014). 

Available at http://investors.nrg.com/phoenix.zhtml

?c=121544&p=irolnewsArticle&ID=1991552. 

715EPA Green Power Partnership, Renewable 

Energy Certificates July 2008). Available at http:// 

www.epa.gov/greenpower/documents/gpp_basicsrecs.pdf. 

716FERC 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/E-28.pdf 

(accessed 11/7/2014). 

717Heeter, J. Quantifying the Level of Cross-State 

Renewable Energy Transactions. NREL 2015. 

Available at http://www.nrel.gov/docs/fy15osti/

63458.pdf. 

portion (1,670 megawatts) of the 

planned RE is solar.712 Ameren is 

planning to retire one-third of the coal 

generating capacity, as well as installing 

an additional 400 megawatts of wind, 

445 megawatts of solar, and 28 

megawatts of hydroelectric generating 

capacity.713

Independent power producers (IPPs) 

also can and do own both RE and fossil 

generation. For example, NRG is a 

diversified IPP that operates substantial 

coal, natural gas, wind, solar, and 

nuclear capacity. NRG demonstrates the 

ability of IPPs to reduce utilization of 

fossil fuel-fired EGUs and replace that 

generation with RE. NRG announced a 

goal to cut CO2 emissions from its fleet 

by 50 percent by 2030 (from a 2014 

baseline).714 NRG has already reduced 

CO2 emissions from its fleet by 40 

percent since 2005. This achievement 

demonstrates that when an IPP commits 

to shifting its generation portfolio, it can 

do so at reasonable cost and without 

reliability impacts. The NRG example 

shows that reduced utilization of fossil 

fuel-fired EGUs that is replaced by RE 

also owned by the EGU owner is 

adequately demonstrated. 

EGU owners can also replace fossil 

fuel-fired generation with RE through 

bilateral contracts and REC purchases, 

as described below. Both the bilateral 

market for RE contracts and REC 

markets are well-developed. There are 

no legal or technical obstacles to a fossil 

fuel-fired EGU owner acting as the 

counterparty of a bilateral contract for 

purchase of energy from a RE facility. 

Any type of EGU owner (utility or 

otherwise) can purchase and retire 

RECs. The fact that RECs are purchased 

by a diverse set of market participants— 

including residential consumers, 

commercial businesses, and industrial 

facilities—demonstrates that such a 

purchase for all EGU owners is 

adequately demonstrated. 

5. REC Markets 

Affected EGU owners do not need to 

directly invest in, or own, renewable 

generating capacity in order to replace 

fossil fuel-fired generation with RE as an 

emission reduction measure. RECs are 

used to demonstrate compliance with 

state RE targets, such as state RPS, and 

also to substantiate claims stemming 

from RE use. RECs are tradable 

instruments that are associated with the 

generation of one megawatt-hour of RE 

and represent certain information or 

characteristics of the generation, called 

attributes.715 RECs may be traded and 

transferred regardless of the actual 

energy flow. 

The legal basis for RECs is established 

by state statutes and administrative 

rules. Nearly all states with a mandatory 

RPS have established RECs as a means 

of compliance. The Federal Energy 

Regulatory Commission (FERC) has 

observed that states created RECs to 

facilitate programs designed to promote 

increased use of RE, and that ‘‘attributes 

associated with the [RE] facilities are 

separate from, and may be sold 

separately from, the capacity and 

energy.’’ 716

In complying with states’ RPS 

requirements, utilities have contracted 

for RECs from in-state and out-of-state 

resources in accordance with RPS 

requirements. Utilities may have 

sourced RECs from out-of-state to 

reduce the cost of compliance, to source 

RECs from specific generation types, or 

for other reasons.717

The development of REC markets to 

facilitate RPS compliance provides 

evidence that markets can develop to 

facilitate compliance with rate-based 

state plans. These markets will afford 

affected EGU owners an alternative to 

directly invest in, or own, renewable 

generating capacity in order to replace 

fossil fuel-fired generation with RE as an 

emission reduction measure. 

6. Quantification of RE Generation 

Potential for BSER and Major Comments 

The methodology for quantifying RE 

generation levels under building block 3 

is a modified version of the alternative 

RE approach from proposal, with 

adjustments that reflect the data and 

information the EPA collected through 

stakeholder comments and the EPA’s 

additional analysis and information 

collection. In evaluating the proposed 

and alternative RE approaches 

commenters observed that RPS, as the 

basis for quantifying RE generation 

levels under the proposed approach, are 

policy instruments that states may 

choose to implement for a variety of 

reasons not related to CO2 emission 

reductions. Additionally, differences 

across RPS policies in eligible resources, 

crediting mechanisms, deliverability 

requirements, alternative compliance 

payments, and other policy elements 

made the regional averaging of statelevel RPS requirements challenging. 

Finally, commenters provided data 

demonstrating that RE resource 

potential can vary significantly within 

the regions identified under the 

proposed approach, producing statelevel RE generation levels that may not 

be aligned with the opportunity to 

deploy incremental RE resources at 

reasonable cost. In contrast, commenters 

argued that a methodology similar to the 

alternative RE approach, which is based 

on economic potential, represents a 

more technically sound basis for 

quantifying building block 3 target 

generation levels that accounts for 

regional differences in RE resources and 

power market conditions, such as 

projected fuel prices, load growth and 

wholesale power prices. The EPA agrees 

with these comments. 

Within the framework of the 

alternative RE approach, the EPA 

received significant comments on a 

number of issues, including the use of 

historical deployment rates, the 

interstate nature of RE and the power 

system, merits of total versus 

incremental RE generation as the metric 

by which building block 3 generation 

levels are quantified, types of RE 

technologies that contribute to those 

generation levels, cost and performance 

estimates associated with those RE 

technologies, magnitude of the reduced 

cost applied to new RE capacity as an 

incentive to deploy, and application of 

a nationally uniform benchmark 

development rate to modeled 

projections of economic deployment. 

Based on commenter data and 

information, as well as further analysis 

and information collection, the primary 

adjustments the EPA made to the 

alternative RE approach are: 

• The basis for quantifying building block 

3 generation has been modified to 

incorporate historical deployment patterns 

for RE technologies as well as the economic 

potential identified through modeling 

projections. The introduction of historical 

capacity additions to the final methodology 

further grounds building block 3 generation 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64807 

718Consistent with the October 2014 NODA, 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. 

719For additional information on the updated RE 

cost and performance assumptions used to quantify 

building block 3 generation, refer to the GHG 

Mitigation Measures TSD. 

720The 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. 

721For supporting data, documentation, and 

examples for each step of the quantification 

methodology, refer to the GHG Mitigation Measures 

TSD. 

in demonstrated levels of RE deployment that 

have been successfully incorporated into the 

power system. This adjustment also serves to 

harmonize the approach across all three 

building blocks in which historical data is 

the primary basis for identifying emission 

reduction opportunities under the BSER. 

• The RE technologies used to quantify 

building block 3 generation levels are 

onshore wind, utility-scale solar PV, 

concentrating solar power (CSP), geothermal 

and hydropower. Each of these technologies 

is a utility-scale, zero-emitting resource that 

was included under the alternative RE 

approach at proposal. Additionally, the EPA 

received significant comments on the 

opportunities and challenges associated with 

distributed RE technologies. Distributed 

technologies, as a demand-side resource, 

present unique data and technical challenges 

(such as the role of evaluation, measurement 

and verification (EM&V) procedures in 

verifying their production, the diverse 

economic incentives of different parties 

involved in their deployment, and the variety 

of grid integration policies and conditions 

across potential deployment sites) that 

complicate identifying a technically feasible 

and 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.K of this 

preamble, distributed RE technologies that 

meets eligibility criteria may be used for 

compliance). Finally, any RE technology that 

has not been deployed in the U.S., including 

demonstrated RE technologies for which 

there is clear evidence of technical feasibility 

and 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 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.718

Specifically, the generation levels under 

building block 3 include generation from 

capacity that commenced operation 

subsequent to 2012 (the data year on which 

the BSER is evaluated). Commenters 

remarked that it is unnecessary to include 

generation from RE capacity that was already 

in operation by 2012 in building block 3 

because the impact of that generation on 

fossil fuel-fired EGUs is already reflected in 

the observed 2012 emissions and generation 

data of those EGUs. 

• Due to the interstate nature of RE and the 

power system, and consistent with the 

rationale provided in the October 2014 

Notice of Data Availability (NODA), building 

block 3 generation levels are quantified for 

each of the three BSER regions—the Eastern 

Interconnection, Western Interconnection, 

and Texas Interconnection—rather than at 

the state-level. This regionalized approach, as 

described in the NODA, takes into account 

the opportunity to develop regional RE 

resources and thus better aligns building 

block 3 generation levels with the rule’s 

approach to allowing the use of qualifying 

out-of-state renewable generation for 

compliance. 

• Commenters observed that the cost and 

performance estimates the EPA relied on at 

proposal from the Energy Information 

Administration’s Annual Energy Outlook 

2013 do not reflect the decline in cost and 

increase in performance that have been 

demonstrated by current projects, 

particularly in regards to wind and solar 

technologies. Commenters provided data 

from a variety of sources to support these 

claims, including Lawrence Berkeley 

National Laboratory (LBNL), the Department 

of Energy (DOE) and Lazard. Each of these 

sources supported the contention that RE 

technologies, particularly wind and solar, 

have realized gains in cost and efficiency at 

a scale that has altered the competitive 

dynamic between RE and conventional 

resources. As a result, it has become 

increasingly necessary for any long-term 

outlook of the utility power sector to 

continually assess the development of RE 

technology cost and performance trends. In 

performing this task, the EPA revised its data 

for onshore wind and solar technologies to 

reflect the mid-case estimates from the 

National Renewable Energy Laboratory’s 

(NREL’s) 2015 Annual Technology Baseline. 

The EPA selected the NREL 2015 Annual 

Technology Baseline (ATB) estimates based 

on the quality of its data as well as NREL’s 

demonstrated success in both reflecting and 

anticipating RE cost and performance trends. 

In addition to wind and solar technologies, 

the EPA evaluated hydropower deployment 

potential based on the latest cost and 

performance data from NREL’s Renewable 

Energy Economic Potential study.719

• The benchmark development rate that 

constrained cost-effective RE deployment 

under the alternative RE approach in the 

proposal has been removed from the final 

methodology.720 Commenters detailed 

several issues with applying the benchmark 

development rate, including that it does not 

factor in the total size of the RE resource in 

a given state and is inconsistent with a 

regional approach to quantifying target 

generation levels. EPA agrees with these 

comments and the benchmark development 

rate has been eliminated. 

In addition to the comments 

described above, the EPA received 

significant comments on a wide variety 

of topics related to building block 3. 

Many of these comments provided 

helpful information and insights, and 

have resulted in improvements to the 

final rule. These comments, as well as 

the EPA responses, are available in the 

Response to Comment document. 

The final methodology for quantifying 

incremental RE target generation levels 

contains seven steps. Each step is 

described below.721

First, the EPA collected data for each 

RE technology (onshore wind, utilityscale solar PV, CSP, geothermal and 

hydropower) to determine the annual 

change in capacity over the most recent 

five-year period. From these data, the 

EPA calculated the five-year annual 

average change in capacity and the fiveyear 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 RE 

technology. The first generation level is 

the product of each technology’s fiveyear average capacity change and the 

assumed future capacity factor. The 

second generation level is the product of 

each technology’s five-year maximum 

annual capacity deployment and the 

assumed future capacity factor. Table 9 

below shows the data and assumptions 

used for these calculations. 


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64808 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

722Capacity values for utility-scale solar PV are 

expressed in terms of MWDC. The assumed future 

capacity factor for this utility-scale solar PV 

includes a DC-to-AC conversion, enabling the 

generation totals to be combined across all RE 

technologies. 

723Refer to GHG Mitigation Measures TSD for 

more detail on modeling methodology. 

724Regions that have already exceeded these 

limits are held at historical percent of net energy 

for load. 

725 2013 Wind Technologies Market Report. 

LBNL. August 2014. Available at http://emp.lbl.gov/ 

sites/all/files/2013_Wind_Technologies_Market_

Report_Final3.pdf. 

Grid Integration and the Carrying Capacity of the 

U.S. Grid to Incorporate Variable Renewable 

Energy. NREL. Cochran et al., April 2015. http://

energy.gov/sites/prod/files/2015/04/f22/QER%20

Analysis%20%20Grid%20Integration%20and%20

the%20Carrying%20Capacity%20of%20the%20US

%20Grid%20to%20Incorporate%20Variable%20

Renewable%20Energy_1.pdf. 

The Western Wind and Solar Integration Study 

Phase 2. NREL. Lew et al., 2013. Available at http:// 

www.nrel.gov/docs/fy13osti/55588.pdf. Refer to 

GHG Mitigation Measures TSD for further analysis. 

726Refer to the GHG Mitigation Measures TSD for 

additional information on constraints related to 

deployment of non-dispatchable RE. 

TABLE 9—HISTORICAL CAPACITY CHANGES AND ASSOCIATED GENERATION LEVELS

Assumed 

future 

capacity 

factor 

(percent) 

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) 

Utility-Scale Solar PV 722 ..................................................... 20.7 1,927 3,494,268 3,934 7,133,601 

CSP ...................................................................................... 34.3 251 754,175 767 2,304,590 

Onshore Wind ...................................................................... 41.8 6,200 22,702,416 13,131 48,081,520 

Geothermal .......................................................................... 85.0 142 1,057,332 407 3,030,522 

Hydropower .......................................................................... 63.8 141 788,032 294 1,643,131 

Total Generation ........................................................... N/A N/A 28,796,222 N/A 62,193,363 

Fourth, the EPA quantified the RE 

generation from capacity commencing 

operation after 2012 that can be 

expected in 2021 (the year before this 

rule’s first compliance period) without 

the imposition of this rule. Because 

building block 3 is focused on the 

ability of fossil fuel-fired EGUs to 

reduce their emissions by deploying 

incremental RE, it is reasonable to take 

into account the considerable amount of 

RE deployment that is already taking 

place and is projected to continue doing 

so before considering the additional 

deployment that would be motivated by 

this rule’s mandate to reduce emissions 

from affected EGUs. The EPA 

considered its base case power sector 

modeling projections using IPM to 

quantify this component of future-year 

RE generation, which the EPA assumes 

to be 213,084,125 megawatt-hours in 

2021. 

Fifth, the EPA applied the generation 

associated with the five-year average 

capacity change to the first two years of 

the interim period. Combining the 

projected 2021 RE generation from 

capacity starting operation after 2012 

with the generation increment 

associated with the five-year average 

change in capacity produces 

241,880,347 megawatt-hours in 2022 

and 270,676,570 megawatt-hours in 

2023. The EPA believes it is appropriate 

to apply the generation associated with 

the 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 the higher RE deployment 

levels assumed for later years. 

Sixth, for all years subsequent to 2023 

the EPA applied the generation 

associated with the maximum annual 

capacity change from the historical data 

analysis. In 2024, this produces a 

building block 3 generation level of 

332,869,933 megawatt-hours (aggregated 

across all three BSER regions); by 2030, 

that generation level is 706,030,112 

megawatt-hours. 

Seventh, to further evaluate the 

technical feasibility and costeffectiveness of the building block 3 

generation levels (aggregated across all 

three BSER regions), as well as to 

produce interconnection-specific levels 

of building block 3 generation from the 

national totals described in steps 5 and 

6, the EPA conducted analysis using 

IPM of a scenario directing the power 

sector to achieve those RE generation 

levels. IPM modeling projections assess 

opportunities for RE deployment in an 

integrated framework across power, 

fuel, and emission markets. The 

modeling framework incorporates a host 

of constraints on the deployment of RE 

resources, including resource 

constraints such as resource quality, 

land use exclusions, terrain variability, 

distance to existing transmission, and 

population density; system constraints 

such as interregional transmission 

limits, partial reserve margin credit for 

intermittent RE installations, minimum 

turndown constraints for fossil fuelfired EGUs, and short-term capital cost 

adders to reflect the potential added 

cost due to competition for scarce labor 

and materials; and technology 

constraints such as construction lead 

times and hourly generation profiles for 

non-dispatchable resources by 

season.723 Additionally, the EPA 

assumes in this analysis that 

deployment of variable, nondispatchable RE resources is limited to 

20 percent of net energy for load by 

technology type and 30 percent of net 

energy for load in total at each of IPM’s 

64 U.S. sub-regions.724 The 30 percent 

constraint applied to variable, nondispatchable RE resources reflects levels 

commonly modeled in grid integration 

studies at the level of the 

interconnection. These studies have 

demonstrated that impacts to the grid in 

reaching levels as high as 30 percent of 

net energy for load are relatively 

minor.725 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 the 

30 percent constraints at the IPM subregion level is very conservative and 

provides a high degree of assurance that 

the RE capacity deployment pattern 

projected by the model would not incur 

significant grid integration costs.726

In addition to facilitating the EPA’s 

assessment of the feasibility and cost of 

reaching the aggregate building block 3 

generation levels across all three BSER 

regions, the IPM projections also 

provide the EPA with a basis for 

apportioning those generation levels to 

each interconnection. The EPA 

considered the projected regional 

location of the evaluated RE deployment 

in this analysis, which shows the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64809 

majority of such deployment occurring 

in the Eastern Interconnection. The 

GHG Mitigation Measures TSD 

describes in greater detail the process by 

which the EPA calculated the 

apportionment of building block 3 

generation levels to each of the BSER 

regions, taking these modeling 

projections into account. Table 10 

describes the annual building block 3 

generation levels for each 

interconnection from 2022 through 

2030. 

TABLE 10—BUILDING BLOCK 3 GENERATION LEVELS (MWh). 

Year Eastern 

interconnection 

Western 

interconnection 

Texas 

interconnection 

2022 ..................................................................................................................... 166,253,134 56,663,541 18,963,672 

2023 ..................................................................................................................... 181,542,775 60,956,363 28,177,431 

2024 ..................................................................................................................... 218,243,050 75,244,721 39,382,162 

2025 ..................................................................................................................... 254,943,325 89,533,078 50,586,893 

2026 ..................................................................................................................... 291,643,600 103,821,436 61,791,623 

2027 ..................................................................................................................... 328,343,875 118,109,793 72,996,354 

2028 ..................................................................................................................... 365,044,150 132,398,151 84,201,085 

2029 ..................................................................................................................... 401,744,425 146,686,508 95,405,816 

2030 ..................................................................................................................... 438,444,700 160,974,866 106,610,547 

Through the quantification 

methodology detailed above, the EPA 

has identified amounts of incremental 

RE generation that are reasonable, rather 

than the maximum amounts that could 

be achieved while preserving the costeffectiveness of the building block. For 

example, assuming gradual 

improvement in RE technology capacity 

factors consistent with historical trends, 

expanding the portfolio of RE 

technologies that contribute to the 

building block 3 generation level, and 

applying the five-year maximum 

capacity change values to all years of 

the interim period are adjustments that 

would produce higher building block 3 

generation levels and maintain the 

primacy of historical data in quantifying 

RE generation potential. External 

analysis and studies of RE penetration 

levels strongly support the technical 

feasibility and cost-reasonableness of RE 

deployment well in excess of the levels 

established by building block 3, as 

detailed in section V.E.7. By identifying 

reasonable rather than maximum 

achievable amounts, we are increasing 

the assurance that the identified 

amounts are achievable by the source 

category and providing greater 

flexibility to individual affected EGUs to 

choose among alternative measures for 

achieving compliance with the 

standards of performance established for 

them in their states’ section 111(d) 

plans. 

7. Feasibility of RE Deployment 

The 2030 level of RE deployment and 

the rate of progress during the interim 

period in getting to that level are well 

supported by comments received, DOE 

and NREL analysis, and external studies 

evaluating the costs of and potential for 

RE penetration. The EPA has assessed 

the feasibility of RE in terms of 

deployment potential, system 

integration, reliability, backup capacity, 

transmission investments, and RE 

supply chains. 

Historical RE deployment rates are a 

strong indication of the feasibility of the 

2030 level of deployment and interim 

period pathway. The use of RE 

continues to grow rapidly in the U.S. In 

2013, electricity generated from RE, 

including conventional hydropower, 

represented 12 percent of total U.S. 

electricity, up from 8 percent in 2005. 

In particular, there has been substantial 

growth in the wind and solar markets in 

the past decade. Since 2009, wind 

energy has tripled and solar has grown 

tenfold. 

The expected future capacity 

installations in 2022–2030 needed to 

reach the 2030 level of incremental RE 

generation are consistent with historical 

deployment patterns. Forecasts by 

Cambridge Energy Research Associates 

(CERA) of 17 gigawatts in 2015 and 

historical deployment of 16 gigawatts in 

2012 are significant. The average 

deployment of wind over the past five 

years was 6,200 megawatts per year; 

2014 deployment of solar PV, both 

distributed and utility-scale, was 6,201 

megawatts. This contribution from solar 

PV is consistent with the rapid 

reduction in costs that is currently being 

observed and is expected to continue. 

Grid operators are reliably integrating 

large amounts of RE, including variable, 

non-dispatchable RE today. For 

example, Iowa and South Dakota 

produced more than 25 percent of their 

electricity from wind in 2013, with a 

total of nine states above 12 percent and 

17 states at more than 5 percent. 

California served nearly 19 percent of 

total load in 2013 with RE resources, not 

including behind-the-meter distributed 

solar resources, and approximately 25 

percent of total load with RE in 2014. 

On an instantaneous basis, California is 

regularly serving above 25 percent of 

load with RE resources, recently began 

seeing over 5,000 megawatt-hours of 

solar energy, and is on track for 33 

percent of load with no serious 

reliability or grid integration issues. 

Germany exceeded 28 percent nonhydro RE as a percentage of total energy 

in first half of 2014. Other recent 

examples include: ERCOT met 40 

percent of demand on March 31, 2014 

with wind power; SPP met 33 percent 

of demand on April 6, 2013 with wind 

power; and, Xcel Energy Colorado met 

60 percent of demand on May 2, 2013 

with wind power. Operational and 

technical upgrades to the power system 

may be required to accommodate high 

levels of variable, non-dispatchable RE 

like wind and solar over longer time 

periods; however, the penetration levels 

cited above have been achieved without 

negative impacts to reliability due in 

large part to low-cost measures such as 

expanded operational flexibility and 

effective coordination with other 

regional markets. 

RE can contribute to reliable system 

operation. The abundance and diversity 

of RE resources in the U.S. can support 

multiple combinations of RE in much 

higher penetrations. When California, 

the Midwest, PJM, New York, and New 

England experienced record winter 

demand and prices during the polar 

vortex, wind generation played a key 

role in maintaining system reliability. 

Wind and solar PV are increasingly 

productive and capable of being 

accurately forecast, which improves grid 

reliability. Increasing capacity factors 

mean less variability and more 

generation. While the wind industry 

develops more projects at lower wind 

speed sites, wind turbine design 

changes are driving capacity factors 

higher among projects located in a given 


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64810 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

727LBNL, Wind Technologies Market Report 

2013, August 2014, p. 43, Available at: http://

emp.lbl.gov/sites/all/files/2013_Wind_

Technologies_Market_Report_Final3.pdf. 

728Refer to the GHG Mitigation Measures TSD for 

further analysis and IPM run results. 

729See Section VIII.K. for a description of 

qualifying RE technologies for compliance. 

wind resource regime.727 Average 

capacity factors have risen from the low 

30 percent range to high 30 percent 

range and continue to improve. One key 

recent advancement is the increasing 

use of turbines designed for low to 

medium wind speed sites (with higher 

hub-heights and larger rotors, relative to 

nameplate capacity) at higher windspeed sites with low turbulence. 

New variable RE generators can 

provide more electrical power grid 

support services beyond just energy. 

Modern wind turbine power electronics 

allow turbines to provide voltage and 

reactive power control at all times. 

Wind plants meet a higher standard and 

far exceed the ability of conventional 

power plants to ‘‘ride-through’’ power 

system disturbances, which is essential 

for maintaining reliability when large 

conventional power plants break down. 

Xcel Energy sometimes uses its wind 

plants’ exceedingly fast response to 

meet system need for frequency 

response and dispatchable resources. 

Utility-scale PV can incorporate control 

systems that enable solar PV to 

contribute to grid reliability and 

stability, such as voltage regulation, 

active power controls, ramp-rate 

controls, fault ride through, and 

frequency control. Solar generation is 

capable of providing many ancillary 

services that the grid needs but, like 

other generators, needs the proper 

market signals to trade energy 

generation for ancillary service 

provision. 

The transmission network can 

connect distant high-quality RE to load 

centers and improve reliability by 

increasing system flexibility. 

Investments in transmission and 

distribution upgrades also enable 

improvements in system-wide 

environmental performance at lower 

cost. 

The potential range of new 

transmission construction is within 

historical investment magnitudes. 

Under nearly all scenarios analyzed for 

the DOE’s Quadrennial Energy Review, 

circuit-miles of transmission added 

through 2030 are roughly equal to those 

needed under the base case, and while 

those base case transmission needs are 

significant, they do not appear to exceed 

historical annual build rates. DOE’s 

Wind Vision findings project 11.5 

gigawatts of wind per year from 2021– 

2030. This deployment level would 

require 890 circuit miles per year of new 

transmission; 870 miles per year have 

been added on average between 1991 

and 2013. 11.5 gigawatts per year is 

consistent with building block 3 

deployment levels for wind capacity 

over the compliance period. DOE’s 

SunShot scenario, which increases 

utility-scale PV to 180 gigawatts by 

2030, required spending of $60 billion 

on transmission through 2050. On an 

average annual basis, this expenditure is 

within the historical range of annual 

transmission investments made by IOUs 

in recent decades. 

Incremental grid infrastructure needs 

can be minimized by repurposing 

existing transmission resources. 

Transmission formerly used to deliver 

fossil-fired power to distant loads can— 

and is—being used to deliver REwithout 

new infrastructure. First Solar’s Moapa 

project uses transmission built to 

deliver coal-fired power from Navajo to 

Los Angeles. NV Energy’s retirement of 

Reid-Gardner will free up additional 

transmission capacity. The Milford 

wind projects in Utah already utilize 

transmission that was built to deliver 

coal power to Los Angeles. 

Storage can be helpful but is not 

essential for the feasibility of RE 

deployment because there are many 

sources of flexibility on the grid. DOE’s 

Wind Vision and many other studies 

have found an array of integration 

options (e.g., large balancing areas, 

geographically dispersed RE, weather 

forecasting used in system operations, 

sub-hourly energy markets, access to 

neighboring markets) for RE beyond 

storage. Storage is a system resource, as 

its value for renewables is a small share 

of its total value. 

Increasing regional coordination 

between balancing areas will increase 

operational flexibility. The Energy 

Imbalance Market (EIM) recently 

implemented by the California ISO and 

Pacificorp is a good example of the 

increased coordination that will be 

helpful in ensuring that resources across 

the West are being utilized in an 

efficient way. 

Significant wind and solar supply 

chains have developed in the past 

decade to serve the fast-growing US RE 

market. For wind, domestic production 

capability would likely have to increase 

to accommodate projected builds under 

the CPP in the 2022–2030 time period; 

however, the global supply chain has 

expanded significantly to serve multiple 

markets and can augment production 

from the domestic supply chain, if 

necessary. At the start of 2014, the U.S. 

domestic supply chain could produce 

10,000 blades (6.2 gigawatts) and 4300 

towers (8 gigawatts) annually. It is not 

anticipated that expanded domestic 

manufacturing will be constrained by 

raw materials availability or 

manufacturing capability. For solar 

technologies, the global supply chain 

has a capacity that has significantly 

expanded over the past few years from 

1.4 gigawatts per year in 2004 to 22.5 

gigawatts per year in 2011. Current 

capacity exceeds these levels and is 

expected to grow. For PV systems, raw 

materials like tellurium and indium are 

at highest risk of supply shortage, but 

these materials are not used in the PV 

technologies currently being deployed 

at large-scale. 

8. Cost of CO2 Emission Reductions 

From RE Generation 

The EPA believes that RE generation 

at the levels represented in building 

block 3 can be achieved at reasonable 

costs. In the EPA’s modeling of the 

building block 3 generation level, the 

projected cost of achieving CO2

reductions through this expansion of RE 

generation is $37 per ton on average 

from 2022 through 2030.728 There are a 

number of reasons why the EPA 

believes that the cost of CO2 emission 

reductions from RE generation will be 

lower than this analysis suggests. First, 

modeling constraints that restrict 

variable, non-dispatchable RE 

technologies to 30 percent of net energy 

for load at each of the 64 U.S. IPM 

regions is a conservative limit intended 

to eliminate significant grid integration 

costs at increased levels of RE 

penetration. In fact, many regions have 

already demonstrated levels of RE 

penetration that exceed the constraints, 

and in practice intermittency can be 

managed across larger regions than the 

64. Consequently, the extent to which 

these regions could, in practice, achieve 

higher levels of RE deployment without 

facing substantial grid integration costs 

would lead to a lower-cost RE outcome 

than is estimated by this analysis. 

Second, there are multiple RE 

technologies not quantified under 

building block 3 that affected EGUs may 

use to demonstrate compliance 

(distributed generation technologies, 

offshore wind, etc.). Based on 

preliminary analysis from DOE and 

NREL, cost-effective opportunities for 

distributed generation alone could 

satisfy one-third to over one-half of the 

stringency associated with building 

block 3.729 Third, as discussed in 

section V and VI of the preamble, the 

BSER reflects the degree of emission 

limitation achieved through the 

application of the building blocks in the 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64811 

730For 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. 

731The only natural gas fired EGUs currently 

considered affected units under the 111(d) 

applicability criteria are NGCC units capable of 

supplying more than 25 MW of electrical output to 

the grid. The data and rates for these units represent 

all emissions and MWh output associated with both 

the combustion turbines as well as all associated 

heat recovery steam generating units. The 

remainder of the section will use the term ‘‘NGCC’’ 

to collectively refer to these natural gas fired EGUs. 

732As 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). 

least stringent region. By definition, in 

the other two regions the BSER is less 

stringent than the simple combination 

of the three building blocks, rendering 

a portion of the emission reduction 

potential quantified by the building 

blocks unnecessary to achieving the 

interim and final CO2 emission 

performance rates. For example, the 

EPA has calculated that in excess of 

160,000,000 megawatt-hours of building 

block 3 potential is not required to 

achieve the final CO2 emission 

performance rates in 2030—and would 

be accessible to affected EGUs for 

compliance.730 Therefore, it is 

reasonable to expect that it would cost 

less to achieve the component of 

building block 3 potential that is 

reflected in the calculation of the final 

CO2 emission performance rates, as 

compared to the results of this analysis 

which assumed achievement of the 

entire quantified building block 3 

potential. The EPA believes that these 

factors provide significant opportunities 

for achievement of the building block 3 

generation levels at lower costs than 

estimated in this analysis. 

VI. Subcategory-Specific CO2 Emission 

Performance Rates 

A. Overview 

In this section, the EPA sets out 

subcategory-specific CO2 emission 

performance rates to guide states in 

development of their state plans. The 

emission performance rates reflect the 

emission rates for two generating 

subcategories affected by the rule (fossil 

steam generation and gas-fired 

combustion turbines).731 These final 

emission performance rates reflect the 

EPA’s quantification of the BSER based 

on the three building blocks described 

in section V above. This procedure 

follows a similar logic to BSER 

quantification at proposal, but it keeps 

the emission performance rates separate 

for fossil steam and NGCC subcategories 

instead of immediately blending them 

together into a single value for all 

affected EGUs. Commenters noted that 

the proposed rule established guidelines 

that were based on the aggregation of 

units, and their reduction potential, in 

a state rather than providing technologyspecific guidelines. While many 

commenters appreciated the flexibility 

this state-focused structure provided, 

some noted two concerns with this 

approach: (1) It would potentially create 

different incentives for the same 

generating technology class depending 

on the state in which that generator was 

located, and (2) it deviated from the 

EPA’s previous interpretation of the 

111(d) regulatory guidelines by not 

providing technology-specific standards 

of performance. In response to these 

comments and our further 

consideration, the final rule establishes 

subcategory-specific emission 

performance rates that are identical 

across units within a subcategory 

regardless of where a unit is located 

within the contiguous U.S. These 

subcategory-specific emission 

performance rates are then translated 

into state-specific goals which, as in the 

proposal, reflect the particular energy 

mix present in each state. That 

translation is presented in section VII. 

These performance rates reflect the 

average emission rate requirement for 

each subcategory. Similar to the 

proposal, they are presented as adjusted 

average emission rates that reflect other 

generation components of BSER (e.g., 

renewable) in addition to the fossil 

component. These performance rates 

must be achieved by 2030 and sustained 

thereafter. The interim performance 

rates apply over a 2022–2029 interim 

period and would be achieved on 

average through reasonable 

implementation of the best system of 

emission reduction (based on all three 

building blocks) described above. In 

other words, the interim performance 

rates are consistent with a reasonable 

deployment schedule of BSER 

technologies as they scale up to their 

full BSER potential by 2030. The 

performance rates are meant to reflect 

emission performance required across 

all affected EGUs when averaged 

together and inclusive of lower-emitting 

BSER components. 

The performance rates are expressed 

in the form of adjusted 732 outputweighted-average CO2 emission rates for 

affected EGUs. However, states are 

authorized to use a converted statewide 

rate-based or mass-based goal as 

discussed in the next section. The EPA 

has determined that the statewide ratebased and mass-based CO2 goals are 

expressions of the emission 

performance rates equivalent to 

application of the emission performance 

rates to affected EGUs within a state. 

The EPA is finalizing the performance 

rates in a manner consistent with the 

proposal, with appropriate adjustments 

based on comments. Stakeholders had 

the opportunity to demonstrate during 

the comment period that application of 

one or more of the building blocks 

would not be expected to produce the 

level of emission reduction quantified 

by the EPA because implementation of 

the building block at the levels 

envisioned by the EPA was technically 

infeasible, or because the costs of doing 

so were significantly higher than 

projected by the EPA. The EPA has 

considered all of this input in setting 

final performance rates. 

The remainder of this section 

addresses two sets of topics. First, we 

discuss several issues related to the 

form of the performance rates. Second, 

we describe the performance rates, 

computation procedure, and 

adjustments made between proposal 

and final based on stakeholder feedback 

in the comment period. 

Some of the topics addressed in this 

section are addressed in greater detail in 

supplemental documents available in 

the docket for this rulemaking, 

including the CO2 Emission 

Performance Rate and Goal 

Computation TSD for CPP Final Rule 

and the Greenhouse Gas Mitigation 

Measures TSD. Specific topics 

addressed in the various TSDs are noted 

throughout the discussion below. 

B. Emission Performance Rate 

Requirements 

The EPA has developed a single 

performance rate requirement for 

existing fossil steam units in the 

contiguous U.S., and a single rate for 

existing gas turbines in the contiguous 

U.S., reflecting application of the BSER, 

based on all three building blocks 

described earlier, to pertinent data. The 

rates are intended to represent CO2

emission rates achievable by 2030 after 

a 2022–2029 interim period on an 

output-weighted-average basis by all 

affected EGUs, with certain computation 

adjustments described below to reflect 

the potential to achieve mass emission 

reductions by avoiding fossil fuel-fired 

generation. 

1. Final Emission Performance Rate 

Requirements 

The emission performance rates are 

set forth in Table 11 below, followed by 


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733As 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. 

734Specifically, 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. 

735However, as discussed in the next section, in 

order to provide maximum flexibility to states, the 

EPA averages these two emission rates together for 

each state using their adjusted 2012 baseline 

generation share to arrive at a single statewide 

emission performance goal. The state has the option 

to comply with this statewide goal through a 

compliance pathway of its choice. This compliance 

pathway may or may not involve requiring its 

affected units to meet the emission performance 

rates. 

a description of the computation 

methodology. 

TABLE 11—EMISSION PERFORMANCE

RATES

[Adjusted output-weighted-average pounds of 

CO2 per net MWh from all affected fossil 

fuel-fired EGUs] 

Subcategory Interim 

rate Final rate 

Fossil Fuel-Fired 

Electric Steam 

Generating Units ... 1,534 1,305 

Stationary Combustion Turbines ......... 832 771 

The emission performance rates are 

expressed as adjusted output-weightedaverage emission rates for each 

subcategory. As discussed later in this 

section, the emission rate computation 

includes an adjustment designed to 

reflect mass emission reductions 

associated with lower-emitting BSER 

components. The adjustment is made by 

estimating the annual net generation 

associated with an achievable amount of 

qualifying incremental lower-carbon 

and zero-carbon generation and 

substituting those MWhs for the 

baseline electricity generation and CO2

emissions from the higher-emitting 

affected EGUs. Under the final rule 

approach, regionally identified building 

block 3 potential generation replaces 

fossil steam and NGCC generation on a 

pro-rata basis corresponding to the 

baseline mix of fossil generation in each 

region. 

2. Interim Emission Performance Rates 

Some commenters suggested that the 

interim period starting in 2020 provided 

too little time for implementation of 

measures required to demonstrate 

compliance during the interim period. 

As discussed in section V.A.3.g of this 

preamble, the EPA has determined that 

an interim period beginning in 2022 

provides sufficient time for states to 

undertake necessary planning exercises 

and for the implementation of measures 

towards achieving the performance 

rates. The EPA determined the interim 

rates in a manner similar to proposal, 

with an adaptation to address the 

revised timing of the interim 

compliance period (beginning in 2022 

rather than in 2020 as proposed). They 

reflect the averaging of estimated 

emission performance rates for each 

year in the interim period (i.e., 2022– 

2029). 

The interim performance rates are less 

stringent than the final 2030 emission 

performance rates because the amount 

of emission reduction potential 

identified for the BSER increases over 

time, as explained in section V. 

C. Form of the Emission Performance 

Rates 

1. Rate-Based Guidelines 

The interim and final emission 

performance rates for fossil steam and 

NGCC units are presented in the form of 

adjusted output-weighted-average CO2

emission rates that the affected fossil 

fuel-fired units could achieve, through 

application of the measures comprising 

the BSER (or alternative control 

methods). Several aspects of this form of 

emission rate are worth noting at the 

outset: The use of emission rates 

expressed in terms of net rather than 

gross energy output; the use of outputweighted-average emission rates for all 

affected EGUs; the use of adjustments to 

accommodate incremental NGCC 

generation and RE measures that reduce 

CO2 emissions by reducing the quantity 

of fossil fuel-fired generation and 

associated emissions; and the 

adjustability of the goals based on the 

severability of the underlying building 

blocks. 

a. Rationale for rate-based guidelines. 

First, the EPA sets an emission rate 

requirement for each subcategory by 

identifying the technology-specific 

reductions available under the building 

blocks. We then give each state the 

choice to apply the emission 

performance rates directly to the 

affected EGUs within the state or 

provides the opportunity to use the 

statewide rate-based goal or the 

equivalent mass-based form translated 

from the emission performance rates for 

state plan purposes. The emission 

performance rates reflect the BSER, and 

the statewide rate-based goal and 

statewide mass-based goal are 

alternative metrics for realizing the 

emission performance rates at the 

aggregate affected fleet level for a state. 

Stakeholders have expressed support 

for having the flexibility to choose from 

among the multiple options for crafting 

an implementation plan to realize the 

BSER. The EPA is providing emission 

performance rate-based guidelines that 

apply uniformly to technology 

subcategories nationwide, and the EPA 

is providing corresponding state 

emission rate goals and state mass goals 

to further enhance compliance 

flexibility for each state. This approach 

allows each state to adopt a plan that it 

considers optimal and is consistent with 

the state flexibility principle that is 

central to the EPA’s development of this 

program. 

b. Net vs. gross MWh. 

The second aspect noted above 

concerns the expression of the goals in 

terms of net energy output 733—that is, 

energy output encompassing net MWh 

of generation measured at the point of 

delivery to the transmission grid rather 

than gross MWh of generation measured 

at the EGU’s generator. The difference 

between net and gross generation is the 

electricity used at a plant to operate 

auxiliary equipment such as fans, 

pumps, motors, and pollution control 

devices. Because improvements in the 

efficiency of these devices represent 

opportunities to reduce carbon intensity 

at existing affected EGUs that would not 

be captured in measurements of 

emissions per gross MWh, goals are 

expressed in terms of net generation. As 

noted by commenters, EGUs have 

familiarity and in some places already 

have in place equipment necessary to 

collect and report hourly net 

generation.734

c. Output-weighted performance rates 

for all affected EGUs. 

This final rule provides an expression 

of the BSER as subcategory-specific 

emission performance rates rather than 

the state goals provided at proposal. 

Whereas the proposal also estimated the 

BSER impact on fossil steam and NGCC 

emissions and generation, it went one 

step further by averaging these two 

technology rates into a single rate for 

each state. Under this final rule, the 

EPA is identifying the fossil steam rate 

and the NGCC rate separately instead of 

only presenting them in a blended 

fashion at the state level.735 These two 

emission performance rates are the 

expression of the BSER for the final rule 

for affected EGUs located within the 

contiguous U.S. 

The modification from a blended 

emission rate in the proposed rule to a 

subcategory-specific emission 

performance rate for affected EGU 

categories in the final rule was made in 

response to comments that technology 


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736The EPA’s responsibility is to determine the 

BSER for all affected EGUs. Some of these under 

construction units may not enter operation until 

2015 or later, but they are likely affected units and 

therefore appropriate to reflect in the baseline and 

corresponding subcategory-specific emission 

performance rates and state goals. 

737The EPA notes that in some cases, it may not 

yet be possible to determine the status of an EGU 

as affected or unaffected without additional data. 

There are potentially some units excluded or 

included in the baseline that will ultimately have 

a different status following an applicability 

determination. However, these cases are limited, 

and the effect of any collective changes to the 

affected fleet inventory will not yield a bias in the 

BSER computation at the regional level. 

738The NEEDS database was also updated to 

reflect the latest data and commenter input on 

under construction units. 

739For purposes of determining emission 

performance rates, the EPA classifies any unit that 

had begun construction prior to Jan. 8, 2014, but 

had not commenced operation by Dec. 31, 2011 as 

‘‘under construction’’. Many of these ‘‘under 

construction’’ units have commenced operation at 

some point during 2012 or prior to signature of this 

final rule. 

740 ‘‘Commence’’ and ‘‘construction’’ are defined 

in 40 CFR 60.2. 

741The baseline inventory relies on historical 

data and does not incorporate anticipated future 

retirements. Most commenters supported this 

treatment as they viewed those scheduled 

retirements (and corresponding emission 

reductions) as an alternative compliance flexibility. 

subcategory-specific emission rates were 

more analogous to prior 111(d) efforts 

and more consistent with the statute. 

The EPA received significant comments 

suggesting a technology subcategoryspecific rate is consistent with past 

section 111(d) regulations. However, 

many commenters also supported the 

flexibility provided to states through a 

state goal metric provided at proposal. 

Therefore, the EPA does provide 

alternative statewide rate-based and 

mass-based goals in the next section. 

The EPA’s main consideration has 

been to ensure that the expression of the 

BSER reflects opportunities to manage 

CO2 emissions by shifting generation 

among different types of affected EGUs. 

Both the performance rates in this final 

rule and the state goals at proposal rely 

on the adjusted emission rate metric to 

reflect that potential shifting. 

Specifically, because CO2 emission rates 

differ widely across the fleet of affected 

EGUs, and because transmission 

interconnections typically provide 

system operators with choices as to 

which EGU should be called upon to 

produce the next MWh of generation 

needed to meet demand, opportunities 

exist to manage utilization of high 

carbon-intensity EGUs based on the 

availability of less carbon-intensive 

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 coalfired 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 the remaining building 

blocks. The sole exception, as described 

above, is the application of building 

block 1 in isolation, which would not be 

implemented independently. The 

performance rates and statewide goals 

that would result from any combination 

of the building blocks could be 

computed using the formulas and data 

included in the CO2 Emission 

Performance Rate and Goal 

Computation TSD for CPP Final Rule 

and its appendices using the 

methodology described below and 

elaborated on in that TSD. 

D. Emission Performance Rate-Setting 

Equation and Computation Procedure 

The methodology used to compute the 

performance rates is summarized on a 

step-by-step basis below in section 3. 

The methodology is described in more 

detail in the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP 

Final Rule, which includes a numerical 

example illustrating the full 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 subcategoryspecific emission performance rates 

reflecting the BSER, the EPA first 

needed to develop a baseline inventory 

of likely affected EGUs in order to 

estimate the impact of the BSER. The 

EPA developed an inventory of likely 

affected units that were operating in 

2012 or that began construction prior to 

January 8, 2014 and that appeared to 

meet the final rule’s applicability 

criteria.736 This inventory does not 

constitute a final applicability 

determination, but best reflects the 

EPA’s estimate of units subject to the 

111(d) applicability criteria as laid out 

in Section IV. The EPA identified a list 

of likely affected units at proposal 

comprised of approximately 3,000 

EGUs. The agency took comment on this 

list and has made a number of updates 

to the inventory in response to those 

comments and in regards to 

applicability criteria changes resulting 

from comments. However, the inventory 

does not reflect a final applicability 

determination, and where a unit’s status 

was unclear, the EPA generally treated 

the unit’s status in a manner consistent 

with the proposal and publically 

available reported data.737

Since the final rule’s applicability 

includes under construction units, the 

EPA also identified units that had not 

yet commenced operation by the 2012 

baseline period, but that commenced 

construction before January 8, 2014. The 

EPA received significant comment on 

the proposal’s sole use of the National 

Electric Energy Data System (NEEDS) to 

identify these under construction units. 

Commenters suggested that the EPA also 

utilize EIA and 2012 proposed unitlevel files to help better identify under 

construction units. In some cases, 

NEEDS did not reflect units that had 

commenced construction. Therefore, the 

EPA updated its approach to identifying 

units that had commenced construction 

prior to January 8, 2014, but that had 

not commenced operation in 2012. In 

the final rule, the EPA uses EIA data, 

comments, as well as NEEDS data to 

identify these under construction 

units.738 739 740

These units that were operating by 

2012 along with those that had not 

commenced operation by 2012 but had 

commenced construction by January 8, 

2014, reflect the EPA baseline inventory 

of likely affected EGUs. The CO2

Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule 

explains the prime mover, capacity, and 

fuel criteria used to identify the likely 

affected EGUs.741

The EPA received significant 

comment that units that came online 

during the baseline year (e.g., 2012) 

should be treated as under construction 

rather than operating units in 2012 for 

purposes of estimating baseline values, 

because their 2012 operation may be 


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742The 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. 743EIA Form 860, 2012. 

misrepresentative of anticipated futureyear 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 representative first full year 

of operation for that technology class. 

2. Data Year 

In the proposed rule, the EPA 

considered using a historical-year data 

set or a projected-year data set as a 

starting point for applying the 

technology assumptions identified 

under BSER. The EPA proposed using 

2012 data as it was the most recent data 

year for which complete data were 

available when the EPA undertook 

analysis for the proposed rule and it 

reflected actual performance at the state 

level. The EPA took comment on 

alternative data sets. In particular, the 

EPA issued a NODA on October 30, 

2014 (79 FR 64543) in which we 

provided 2010 and 2011 historic data 

for consideration. 

The EPA received a significant 

number of comments supporting the use 

of historical data as the basis from 

which to quantify performance rates 

reflecting BSER. Some commenters 

supported the 2012 data year as the best 

reflection of the power fleet, and some 

suggested that the EPA use a different 

year or a historical average to control for 

data anomalies in 2012. Moreover, some 

commenters pointed out that using 

2010, 2011, 2012 data, or an average of 

the three would not address their 

concerns about recent year anomalies in 

hydro generation due to high snow 

pack. Some commenters also suggested 

the EPA use a baseline including years 

prior to 2012, not to increase 

representativeness of the power sector, 

but as a means of recognizing early 

action. 

In this final rule, the EPA is taking an 

approach to the baseline year where we 

still largely rely on reported 2012 data 

as the best and most recent available 

data representing the power sector from 

which to apply the BSER, but also 

including targeted baseline adjustments 

to address commenter concerns with 

2012 data.742 Below, we explain why— 

at the nationwide level—2012 data are 

preferable, more objective, and more 

accurate than a prior year, or an average 

of years, for informing the baseline. 

Then, we explain the adjustments that 

we are making to the 2012 data along 

with our rationale for such adjustments, 

in response to comments we received. 

Some commenters supported the 

EPA’s use of 2012 data to inform 

performance rates, and the EPA agrees 

that 2012 data with targeted 

adjustments, relative to other historical 

years, best reflects the power sector and 

best informs the performance rates that 

pertain to the BSER. The EPA believes 

that starting with 2012 data is more 

accurate and better informs the BSER 

than an earlier historical year or 

historical multi-year average for the 

following reasons: 

(1) Of the historical data fully available at 

the time the proposal analysis began, 2012 

was the most recent and best reflects the 

power fleet. Approximately 43 GW of new 

capacity came online in 2010 and 2011. In 

other words, there was 43 GW of capacity 

online as of 2012 that had not been in service 

at some point during the 2010–2011 period. 

Likewise, approximately 17 GW of capacity 

that were operable in 2010 and/or 2011 were 

retired prior to 2012.743 Using state-level, 

prior year data, either on its own, or as part 

of a multi-year baseline, is not as 

representative of the current power fleet as 

the 2012 data, which better reflects 

significant changes in power sector 

infrastructure. 

(2) A three-year baseline would not address 

some of the substantive concerns raised by 

commenters. Many commenters pointed out 

that using a three-year baseline would not 

address their critical concern about variation 

in the hydrological cycle due to snow pack 

(particularly in the Northwest), because the 

snow pack was significantly above average in 

both 2011 and 2012. The EPA agrees with 

commenters that we can better address their 

baseline data concerns regarding an average 

hydro year by identifying those states with a 

significant share of hydro generation and 

variation in that hydro generation, and 

making targeted adjustments to those states’ 

affected fossil generation levels in order to 

reflect a more typical snow-pack year. This 

procedure is described in more detail below 

and in theTSDs. 

(3) In addition to being, in the EPA’s view, 

a less representative baseline of the existing 

power fleet, a multi-year baseline would also 

likely entail complexity when determining 

how to average together yearly fleet data 

while appropriately accounting for fleet 

changes occurring during those years. The 

2012 baseline starting point maximizes the 

EPA’s reliance on latest reported operating 

data and minimizes the need for fleet 

capacity adjustments. For instance, because 

of year-to-year fleet turnover, the averaging of 

multiple baseline years would require 

additional assumptions in regards to which 

generation to consider from a fleet that is 

changing in a given state or region (or even 

where units are switching fuel sources such 

as a coal-to-gas conversion). 

(4) Due to the region-based approach to 

quantify building blocks and the BSER as 

subcategory-specific emission performance 

rates, variations in unit-level data do not 

significantly impact the calculation of 

emission performance rates. For instance, if 

one fossil unit is operating less in a given 

year due to an outage, another fossil unit in 

the same region is generally operating more. 

Therefore, at the regional level, fossil 

generation and emissions do not vary to the 

same degree that unit-level data varies. 

Moreover, the variation at the regional level 

that does exist in 2012 relative to previous 

years is not necessarily unrepresentative 

variation, but illustrates trends in the power 

sector infrastructure that are desirable to 

capture for purposes of determining a 

representative year from which further 

improvements in CO2 emissions performance 

can be made. Because the EPA is moving 

from a state approach at proposal to a 

regional approach for calculating the 

expression of the BSER in this final rule, 

unit-level operational variation from year to 

year becomes even less relevant to the 

calculation of regional emission performance 

rates. 

(5) Some commenters suggested the EPA 

use an earlier baseline year as a means of 

recognizing early action. They noted that an 

earlier baseline would reflect a higheremitting fleet and therefore when the same 

level of building block MWhs are applied, 

they would result in a higher (i.e., less 

stringent) state goal. The EPA disagrees with 

this view for several reasons. First, the 

objective of selecting a baseline to inform 

BSER is to have one that best reflects the 

power sector and consequently the best 

system of emission reductions of which the 

power fleet is capable. Using an earlier 

baseline that ‘‘inflates’’ the starting point 

would undermine this objective, not serve it. 

Second, the EPA disagrees with the premise 

of this comment—that the baseline would 

change and building block potentials would 

stay the same. For instance, building block 2 

functions based on incremental generation 

potential (incremental generation = potential 

generation¥baseline generation). This 

incremental value would increase if an 

earlier baseline period was used that had less 

existing NGCC generation. 

(6) Some commenters pointed out that the 

EPA relied on multi-year historical data in 

allowance allocation in previous rulemakings 

(e.g., CAIR and/or CSAPR allocations). 

However, that comparison is not relevant to 

the quantification of emission reduction 

potential under 111(d). In those previous 

instances, the EPA was considering typical 

unit-level behavior for allowance 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 


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744While 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. 

745Updated unit-level data reflecting corrections 

identified by commenters to the underlying 2012 

file are provided in Appendix 1 of the CO2

Emission Performance Rate and Goal Computation 

TSD for CPP Final Rule. The adjustments made to 

the aggregate data to address representativeness 

concerns are provided in Appendix 3. 

Hub natural gas prices were lower in 2012 

relative to previous years, this does not 

invalidate the suitability of the data year 

selection. The EPA’s objective in selecting a 

baseline is to identify potential reductions 

when BSER technologies are applied; year-toyear variation in market prices for natural gas 

does not frustrate this effort. For instance, a 

region may have generated only 5 MWh of 

NGCC generation in 2011 when gas prices 

were higher, and 10 MWh of NGCC 

generation in 2012 when gas prices dropped. 

However, this does not change the outcome 

of the quantification of the BSER, because the 

building block is based on the emission 

reduction potential of the fleet. That 

potential (e.g., a fuller realization of the 

existing NGCC generation potential 

equivalent to 15 MWh) does not change 

regardless of the year used for baseline NGCC 

generation. Therefore, a different data year 

may change a baseline data point, but it 

would not change the total potential NGCC 

generation for quantifying the emission 

performance rates in these circumstances. 

In summary, the EPA believes that 

continuing to rely on 2012 data while 

incorporating select data adjustments as 

detailed below is not only a reasonable 

choice and adequately supported, but a 

more reliable and preferable starting 

point for determining the BSER 

requirements. 

3. Adjustments That the EPA Made to 

the 2012 Data 

The EPA made corrections to unitlevel 2012 data based on commenter 

feedback. In addition, we also made 

some adjustments to 2012 data, not to 

address a correction, but to address a 

concern about the representativeness of 

the data. Although the EPA determined 

that the 2012 data year better informed 

its BSER determination than a preceding 

year or a multi-year average, 

commenters did identify some 

limitations that we are addressing 

through targeted adjustments. These are 

discussed below: 

(1) Adjustments to state-level data to 

account for annual variation in the 

hydrologic cycle as it relates to fossil 

generation. 

Hydropower plays a unique role in a 

handful of states in that (1) it is a significant 

portion of their generation portfolio, (2) it 

varies on an annual basis, and (3) 2012 was 

an outlier year for snow-pack (meaning 

hydropower was above and fossil generation 

was below its historical average).The EPA 

notes that these three conditions are not 

present in other weather-based RE 

technologies like solar or wind.744 Therefore, 

no similar adjustment was needed to account 

for weather patterns with these technologies. 

Unlike market conditions (e.g., changes in 

natural gas prices) that may produce different 

generation profiles year-to-year but that do 

not change the overall generating potential of 

the state’s power fleet, variation in the 

hydrologic cycle does fundamentally change 

the generating potential of the state’s power 

fleet in hydro-intensive states as they no 

longer have the same generating potential in 

an average year as they had in a ‘‘high hydro’’ 

year. The CO2 Emission Performance Rate 

and Goal Computation TSD for CPP Final 

Rule provides analysis and explains the 

adjustment that the EPA made to the statelevel 2012 data for Idaho, Maine, Montana, 

Oregon, South Dakota, and Washington to 

better reflect fossil generation levels when 

hydro generation performed at its average 

level as observed over a 1990–2012 

timeframe. The EPA agrees with commenters 

that using a 2010–2012 baseline would not 

address the concern as 2011 was also an 

outlier year relative to historical snow-pack 

and hydro generation. 

(2) Extended unit outages due to 

maintenance. 

Generally, because of the regional-level 

approach to calculate performance rates, the 

EPA does not believe that unit-level 

variations in operation influence the 

subcategory-specific performance rates 

reflecting BSER. For instance, as some units 

ramp down, and others ramp up to replace 

their load at the regional level, total fossil 

generation changes little due to these fossilfor-fossil substitutions. Unit-level variation 

does not inherently entail region-wide 

variation. 

However, the EPA did receive comment 

that in limited cases, this could have a 

substantial impact on an individual state if 

it chooses to use a rate-based or mass-based 

statewide goal. Even though the EPA is 

calculating subcategory-specific performance 

rates that it believes are not affected by this 

type of unit-level variation, it still evaluated 

the possible impacts it may have when 

converting to state goals in the next section. 

The EPA examined units nationwide with 

2012 outages to determine where an 

individual unit-level outage might yield a 

significant difference in state goal 

computation. When applying this test to all 

of the units informing the computation of the 

BSER, emission performance rates, and 

statewide goals, the EPA determined that the 

only unit with a 2012 outage that (1) 

decreased its output relative to preceding and 

subsequent years by 75 percent or more 

(signifying an outage), and (2) could 

potentially impact the state’s goal as it 

constituted more than 10 percent of the 

state’s generation was the Sherburne County 

Unit 3 in Minnesota. The EPA therefore 

adjusted this state’s baseline coal steam 

generation upwards to reflect a more 

representative year for the state in which this 

900 MW unit operates. 

(3) Many commenters also noted that 

because the EPA uses annual data, 2012 was 

not representative for units coming online 

part way through the year. The EPA relies on 

annual data, so if a unit is underrepresented 

in a certain part of the year because it is not 

yet online, then another unit is likely overrepresented 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 overrepresented and under-represented units do 

not necessarily fall within the same state, and 

therefore this potential difference in the state 

location of the affected units could have an 

impact when estimating appropriate 

statewide goals. To address this comment, 

the EPA adjusted the 2012 generation data for 

fossil units coming online during 2012 to a 

more representative annual operating level 

for that type of unit reflecting its incremental 

impact on generation and emissions. This 

effectively resulted in increased baseline 

emissions and generation assumed for those 

units beyond their reported partial-year 

operations in 2012. Conceptually, the 

assumption of full-year operation at units 

that came online partway through 2012 could 

pair with an assumed reduction in the 

operation of other units somewhere in the 

same region. However, the EPA made no 

corresponding deduction to represent this 

likely decreased utilization at other affected 

units because it was impossible to project the 

state location of such units with certainty 

and the assumed utilization level was meant 

to reflect the incremental impact on the 

baseline. As a result, this data adjustment 

increases the total generation and emissions 

for units reporting in the 2012 baseline 

beyond the 2012 reported levels. 

Additionally, as done in proposal, the EPA 

continued to identify under construction 

units that did not begin operation in 2012, 

but had commenced construction prior to 

January 8, 2014 and would commence 

operation sometime after 2012. As described 

in the next section, the EPA estimated 

baseline generation and emissions for these 

units as they had no 2012 reported data. 

In summary, this final rule continues 

to rely on the latest reported 2012 data 

as the foundation for quantifying the 

BSER. However, the EPA has made 

limited adjustments, in addition to 

corrections identified by commenters, to 

the 2012 data to address some of the 

relevant concerns raised by 

commenters. Therefore, the baseline is 

informed by 2012 data, but not limited 

to 2012 data.745

4. Equations 

In this section we describe how we 

develop the equations used to determine 

the emission performance rates for fossil 

steam and NGCC units that express and 

implement BSER. More detailed 


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64816 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

746EGUs whose capacity or fossil fuel combustion 

were insufficient to qualify them as likely affected 

EGUs were not included in the subcategory-specific 

rate and goal computations. Most simple cycle 

combustion turbines (CTs) were excluded on this 

basis at proposal, and all simple cycle CTs were 

excluded at final reflecting changes to the 

applicability language. IGCC’s were designated as 

‘‘other’’ generation at proposal, but they are 

grouped with coal units for purposes the final rule 

category-specific rates. Useful thermal output 

(UTO) was also translated to a MWh equivalent and 

included in state goals at proposal, resulting in 

more stringent rates for states with more 

cogeneration sources, but UTO is not included in 

this final rule emission performance rate or state 

goal calculations as a result of comments regarding 

potentially adverse impacts on cogeneration units 

and uncertainty of thermal load outputs. As 

described in the state plan section of the preamble, 

units may still quantify and convert UTO (i.e., 

taking credit for waste heat capture) when 

demonstrating compliance. See the applicability 

criteria described in Section IV.D above. 

information regarding rate computation, 

including example calculations, can be 

found in the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP 

Final Rule, which is available in the 

docket for this action. Here we first 

present the general principles we follow 

when developing equations to express 

the BSER; then, we summarize the steps 

taken to assemble baseline data to 

reflect 2012 baseline emissions and 

generation, and apply the building 

blocks that constitute the BSER to 

derive performance rates that will be 

used by states to implement BSER. 

Section VII then explains how these 

nationwide performance rates are 

reconstituted into a statewide goal 

metric similar to the proposal in order 

to allow a state (at its discretion) to use 

a statewide goal as a mechanism for 

demonstrating compliance at the 

aggregate state level in a state plan, as 

an alternative to applying the emission 

performance rates to its affected EGUs 

directly. 

When developing equations to 

implement BSER, we adhere to a 

number of basic principles. First, we 

ensure that the equations are consistent 

with the BSER itself, and in particular, 

reflect the redistribution of generation 

among fossil steam, NGCC and 

renewables embodied in building blocks 

2 and 3. In doing this, we account for 

the interactions between building blocks 

in a way that is consistent with the 

assessment of incremental building 

block generation potential and the 

compliance framework for Emission 

Reduction Credits (ERCs). In particular, 

we must ensure that each increment of 

building block 3 emission reduction 

potential is applied to either fossil 

steam or NGCC units but not both. The 

equations we develop must also take 

account of the dual status of existing 

NGCC units, which are simultaneously 

affected units and provide generation 

that is an element of the BSER itself. 

In addition, we are applying the 

BSER, as we have done in calculating 

other section 111(d) standards, to a 

defined population of existing affected 

sources, represented in this case by the 

generation of the source category in the 

2012 adjusted baseline. This provides 

an empirical historical baseline against 

which we define the performance rates 

and their state goal equivalents. In doing 

so, we must account for any offsetting 

increases in emissions that result from 

applying the BSER control measures, as 

we have done in setting other standards. 

For example, when determining BSER 

for particulate matter control, a number 

of pollution control devices (such as 

sorbent injection technologies) 

themselves create particulate matter. If 

the particulate matter created by these 

control devices were not appropriately 

accounted for when developing the 

standard intended to address the 

primary emissions of particulate, this 

could create an unreasonably stringent 

PM standard. In the current context, this 

means recognizing that increasing 

NGCC capacity utilization in accordance 

with building block 2 both offsets higher 

emitting steam generation and increases 

emissions at the NGCC units 

themselves, which are also affected 

entities that must demonstrate 

compliance with the BSER. Thus, it is 

essential that we apply the building 

blocks in a way that avoids creating a 

level of stringency in the performance 

standards for affected EGUs that goes 

beyond what we have determined to be 

the BSER—while at the same time 

ensuring that equations apply the 

building blocks to generate performance 

standards that represent the full 

application of the BSER to the affected 

EGUs. 

Under section 111, the EPA adopts 

emission performance standards that are 

based on the BSER. The emission 

performance rates reflect our 

recognition of the value of giving 

sources the flexibility to adopt 

equivalent emissions reduction 

strategies and measures that for them 

may be preferable (in a specific 

circumstance) to the technologies and 

measures that we define as the BSER. 

An important function of the emission 

performance rates representing the 

BSER is to provide the flexibility 

needed to allow alternative compliance 

options, including the development of 

new technologies or the deployment of 

effective technologies outside of the 

BSER technologies. In the guidelines we 

issued under section 111(d) for landfill 

gas, for example, we adopted the 

primary standard based on flaring of any 

captured landfill gas, but we also 

developed equations that led to an 

expression of the BSER that allowed for 

the alternative of capturing the gas and 

combusting it in an electrical generating 

unit. 

Finally, in deriving the emission 

performance rates, there are a number of 

considerations we took into account. 

First, it is important that the baseline 

from which the rates are derived be 

transparent and based on observable, 

historical data. Second, the emission 

performance rates must reflect the 

emission reductions achievable through 

the best system of emission reduction. 

Because the BSER includes shifting of 

emissions from higher-emitting to 

lower-emitting sources, state 

compliance frameworks will likely 

involve a combination of physical 

measures at the plant (where either rate 

or generation may be reduced) and some 

form of credit for lower-emitting 

generation (or demand side measures) 

outside of the plant. In this context, the 

emission performance rates must 

provide appropriate incentives for 

affected entities to achieve the emission 

reductions encompassed in the BSER, 

including through state plans that 

provide crediting for lower-emitting 

generation. Third, and as set forth 

below, we must account for the EPA’s 

determination that pro rata 

implementation of building block 3 is 

the best reflection of the potential for RE 

to displace both fossil steam and NGCC, 

and the dual role of NGCC units as both 

affected sources and a BSER compliance 

technology. 

This set of considerations was central 

to the development of the BSER 

equations that the EPA describes next. 

They were particularly important for 

steps five through seven below which 

address building blocks 2 and 3, 

building blocks that have both 

significant overlap with each other and 

which impact steam and NGCC units in 

an integrated way. 

Step-by-Step Discussion of Equations 

Step one (compilation of baseline 

data). On a unit-level basis, the EPA 

obtained total annual quantities of CO2

emissions, net generation (MWh), and 

capacity (MW) from reported 2012 data 

for likely affected EGUs that had 

commenced operation prior to 2012.746

The EPA made changes to the historical 

unit-level data based on comments 

received at proposal. For each state and 

region, the agency aggregated the 2012 

operating data for all coal-fired steam 

EGUs as one group, all oil- and gas-fired 

steam EGUs as a second group, and all 

NGCC units as a third group. The EPA 

adjusted these state values upwards in 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64817 

747The EPA notes that we did not identify any 

under construction coal units at proposal, but we 

are using a methodology in this final rule for newly 

categorized under construction coal units similar to 

our under construction assessment of NGCC at 

proposal. 

748The EPA received comment on the assumed 

55 percent capacity factor for under construction 

NGCC EGUs. Some comments suggested the value 

was too large of an estimation for incremental 

generation as some of that 55 percent utilization 

would have a replacement impact on 2012 

operating generation. Others suggested it should be 

larger as a particular planned under construction 

unit was anticipated to have a higher utilization 

rate. The EPA reviewed operating patterns of EGUs 

that came online, and determined a 55 percent and 

60 percent capacity factor assumption for under 

construction NGCC and coal EGUs respectively are 

a reasonable estimate for informing the incremental 

emissions and generation from under construction 

units. It recognizes that some of these units may 

indeed operate at a higher utilization level, but also 

recognizes that some of the generation may have a 

replacement effect instead of an incremental one. 

749The EPA received some comments suggesting 

that under construction units should not be 

included in the quantification of BSER and/or rate 

calculations, and other comments supporting their 

inclusion. The EPA determined that including it 

was consistent with our responsibility under the 

111(d) statute to define a Best System of Emission 

Reduction for existing units. 

750Building 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. 

751Baseline OG steam emissions are added to 

adjusted coal emissions and divided by baseline OG 

steam generation and baseline coal generation. 

a limited number of instances to reflect 

the hydropower and unit outage 

concerns raised in comments and 

described above. As discussed above, 

the EPA first only aggregated the 

reported data for units that commenced 

operation prior to 2012. For those likely 

affected units that commenced 

operation during 2012, the EPA treated 

that capacity consistent with its 

framework for under construction 

affected units, which were added next. 

This was done in response to comments 

recognizing the fact that the year during 

which a unit commences operation may 

not have been representative of its 

potential generation and emissions. 

For the under construction units (i.e., 

those under construction prior to 

January 8, 2014 but which had not 

commenced operation by December 31, 

2011), the EPA estimated their 

incremental impact on the baseline 

generation and emissions using their 

capacity. The EPA assumed a 55 percent 

capacity factor for under construction 

NGCC units and a 60 percent capacity 

factor for under construction fossil 

steam units, which are consistent with 

the values and methodology the EPA 

proposed for under construction 

units.747 These values are informed by 

the 2012 capacity factors for other units 

in these technology classes that recently 

commenced operation.748 Using these 

capacity factors along with the capacity 

for the units, the EPA estimated an 

annual baseline generation value for 

these units. The agency then estimated 

annual baseline CO2 emissions for these 

under construction units using the 

average emission rate of generating units 

of the same technology in the state 

where the under construction unit is 

located. Where no generators of the 

same technology existed in a given state, 

the EPA used the national baseline 

average for that technology. This is 

similar to the adjustment made at 

proposal for under construction units, 

with the main difference being units 

that commenced operation in 2012 are 

now also treated as under construction 

for baseline data purposes in the final 

rule. 

The estimated emissions and 

generation for under construction units 

were added to the 2012 reported 

emissions and generation data for the 

affected units that had already 

commenced operation prior to 2012 to 

derive an adjusted historical baseline 

total for each state that was reflective of 

all likely affected 111(d) sources.749

Step two (aggregation to the regional 

level). The EPA took comment on 

applying building blocks at the regional 

level, and received significant comment 

supporting such an approach. Therefore, 

whereas the proposal aggregated the 

baseline data to the state level, the final 

rule further aggregated it to the regional 

level prior to building block application. 

The regions reflect the Eastern, Western, 

and Texas Interconnections. The shift to 

a regional framework was based on 

comments suggesting that the EPA 

would better capture the interstate 

impacts of the building blocks and 

reflect the interconnected nature of the 

electric grid under a regional structure. 

The basis for the regions is defined and 

discussed in Section V.A.3. 

Step three (identification of source 

category baseline emission rates). As 

discussed in the beginning of this 

section, the EPA took a technologyspecific approach to quantifying 

guidelines. Therefore, whereas the 

proposal first averaged the fossil steam 

rate and NGCC rate together before 

applying the building blocks and 

defining state goals, the final rule 

applied the building blocks at the 

regional level to give a separate fossil 

steam rate and NGCC rate for each 

region. The starting point for calculating 

the subcategory-specific emission 

performance rates was the baseline 

regional emission rates for both fossil 

steam and NGCC in the year 2012 with 

the modifications discussed above. 

Step four (application of building 

block 1). The baseline CO2 emissions 

amount for the coal-fired steam EGU 

fleet in each region was reduced by 2.1, 

2.3, and 4.3 percent in the Western, 

Texas, and Eastern Interconnections 

respectively, while the coal generation 

level was held constant, reflecting the 

EPA’s assessment of the average 

opportunities in each region to reduce 

CO2 emission rates across the existing 

fleet of coal-fired steam EGUs through 

heat rate improvements that are 

technically achievable at a reasonable 

cost. The EPA then averaged together 

the region’s baseline oil- and natural 

gas-fired steam rate with its building 

block 1 adjusted coal steam rate to get 

a fossil steam rate post-building block 

1.750 751

Step five (application of building 

block 3). At proposal, the EPA 

incorporated incremental RE MWhs 

(where incremental means the amount 

above the adjusted 2012 baseline) by 

adding them to the denominator of the 

emission rate goal. In response to 

comments on this approach, the EPA 

issued a NODA discussing an 

alternative methodology of 

incorporating building block 3 in a 

manner more analogous to building 

block 2 treatment, where the 

incremental MWhs identified for the 

building block replace baseline fossil 

MWhs on a one-to-one basis. The EPA 

is adopting this replacement 

methodology for building block 3 in the 

final rule consistent with comments 

noting that such a computational 

procedure better reflects the reduction 

potential of that building block. 

Under this methodology, all of 

building block 2 incremental NGCC 

potential and part of building block 3 

incremental RE potential were 

ultimately applied to replace higheremitting fossil steam generation and 

emissions, while the remaining building 

block 3 potential was applied to replace 

NGCC generation and emissions. 

Commenters noted that under this 

approach building block 3 should be 

applied first, or the EPA would 

understate the potential of building 

block 2 by subtracting out some NGCC 

generation after the 75 percent 

utilization level of NGCC had been 

applied to replace fossil steam. The EPA 

agrees and calculated the building block 

3 impacts first in developing the 

emission performance rates. 

To implement this, first, building 

block 3 replacement potential was 

identified for each region to arrive at a 

total amount of incremental zeroVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00157 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

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752The EPA took comment on a pro-rata or an 

intensity-based replacement approach. In this final 

rule, the EPA agrees with commenters that a prorata approach is a better reflection of the BSER. 

Incremental RE generation has, and is likely to 

continue, to replace both steam and gas turbine 

generation and the BSER captures this through a 

pro-rata distribution of identified building block 3 

potential. 

753For example, if 100 MWh of incremental zero 

emitting generation is available in a given region 

and that region had 70 percent of its affected fossil 

generation coming from fossil steam units in the 

baseline and 30 percent from NGCC units—then 70 

MWhs of the incremental zero-emitting generation 

are applied to baseline fossil steam generation and 

30 MWhs are applied to baseline NGCC generation. 

754 In early years, will be less than 75 percent due 

to building block 2 gradual deployment. 

755The EPA recognizes that real world market 

dynamics will necessarily differ from the BSER 

assumptions, and has designed the emission 

guidelines to provide flexibility beyond the 

emission reduction opportunities identified in the 

BSER. The essential criteria, however, are that the 

emission rates and crediting framework are 

consistent with the BSER and provide the 

incentives needed to facilitate the emission 

emitting generation hours available to 

replace fossil generation in the region. 

Because renewable generation can 

replace both fossil steam and NGCC on 

the grid, the EPA determined that it was 

appropriate to apply these incremental 

zero-emitting generation hours to 

replace generation and associated 

emissions from each of the fossil steam 

and NGCC fleets in the region on a prorata basis in the following manner.752

The EPA determined the percent of 

fossil steam 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 zeroemitting MWhs to each of those 

technology source categories.753 The 

incremental zero-emitting generation 

assigned to each technology replaced 

the same amount of fossil generation 

from that technology’s baseline value. 

Step six (application of building block 

2). If the remaining generation level for 

the NGCC fleet in a region, taking into 

account the previous step’s replacement 

of NGCC generation, was less than 75 

percent of the fleet’s potential 

summertime generating capacity (the 

potential capacity factor the EPA 

determined to represent the BSER), then 

the NGCC generation in the region was 

assumed to increase to levels equal to 

the lesser of (1) its potential at a 75 

percent capacity factor 754 or (2) a 

generation level above which there is no 

longer fossil steam generation remaining 

within the same region to replace. In 

other words, the regional NGCC 

capacity factor was only assumed to 

reach 75 percent if there was sufficient 

higher-emitting fossil steam generation 

that it could replace after step five. The 

increase in NGCC generation at this step 

compared to the post-building block 3 

level was matched by an equal decrease 

in fossil steam generation reflecting the 

1 for 1 MWh hour replacement. At this 

point, the generation for both steam and 

NGCC reflect the final distribution of 

generation between the subcategories 

after application of the building blocks. 

But the emission performance rates 

must account for CO2 emissions and 

generation from incremental gas and 

renewable generation that comprise 

building blocks 2 and 3, to reflect and 

enable the emission reductions 

achievable under the best system of 

emission reduction, and ensure that the 

shared implementation of the BSER by 

steam and NGCC generation is reflected 

in the rates. 

Step seven (accounting for and 

facilitating the emission reductions 

achievable through the implementation 

of the best system of emission 

reduction). 

This step quantifies the aggregate 

emission changes associated with the 

emission rate improvement and 

generation replacement patterns 

described in steps four, five, and six to 

arrive at an adjusted fossil steam 

emission rate and an adjusted NGCC 

emission rate for each region that will, 

as discussed above, (1) enable the 

implementation of all three building 

blocks, (2) be based on observable, 

concrete baselines, and (3) reflect the 

BSER. 

First, in developing the emission 

performance rates, the EPA had to 

answer the question of how to reflect 

the building blocks in the equations 

defining the rates in a manner that 

would enable the generation shifts that 

are essential components of the BSER. 

In the case of building block 3, the EPA 

accomplished this by incorporating the 

pro rata share of incremental (above 

baseline) zero emitting generation into 

the emission rates for each group of 

affected EGUs, thus ensuring that these 

EGUs would have to include a 

corresponding amount of zero-emitting 

generation in their compliance 

calculations, either through the 

acquisition of credits or through some 

other mechanism as determined by their 

state in its implementation plan. 

For building block 2, a similar 

mechanism is needed. Accordingly, a 

portion of the NGCC generation and 

emissions used to replace fossil steam 

must be averaged into the steam rate, 

analogous to what was done with 

building block 3. The EPA considered 

two approaches to define the quantity of 

NGCC generation and emissions to be 

averaged into the steam rate: (1) 

Incremental NGCC generation after the 

implementation of building block 3 and 

(2) incremental NGCC generation from 

baseline levels. For the reasons below, 

the EPA has determined that the second 

approach better reflects the 

considerations discussed above. 

As discussed above, it is beneficial 

that the baseline from which emission 

performance rates are derived be 

transparent and based on observable 

historical data. The first approach, 

however, depends on the level of 

incremental NGCC generation relative to 

what is available after the 

implementation of building block 3. 

This level of NGCC generation (obtained 

after replacing baseline levels of 

generation with NGCC’s pro rata share 

of incremental RE generation) only 

exists as an intermediate step in the 

BSER calculation. It is not based on an 

observable or concrete level of 

generation. 

In Section VIII we discuss methods 

for creating ERCs for implementing 

shifting of generation from steam to 

NGCC, and this discussion illustrates 

the value of relying on an observable 

and concrete baseline. In that section we 

suggest that incentivizing and 

facilitating the purchase of ERCs as a 

compliance option for steam units could 

be implemented through the use of a 

factor that creates a fraction of an 

allowable credit for each hour that an 

NGCC operates. This factor is derived 

from the incremental generation of 

NGCC post-building block 2, relative to 

the baseline. While a different factor 

could be derived from the hypothetical 

intermediate level resulting from the pro 

rata application of zero emitting 

generation to NGCC in building block 3 

(by transferring the full amount of 

NGCC emissions and generation 

replacing steam generation in building 

block 2), the EPA believes that 

grounding baselines in historical data 

(such as those used to derive the 2012 

baseline) is both more transparent and 

easier to understand in a way that is 

more useful to states and utilities, in 

contrast to the practical challenges of 

relying on a calculated level that 

corresponds to an interim step within 

the emission performance rate 

calculation. As long as the crediting 

framework for creating ERCs is 

consistent with the amount of gas 

emissions and generation that is 

transferred to the coal rate, either the 

chosen option or the option of 

transferring the entire quantity of gas 

emissions and generation that occurred 

in step six to the coal rate would 

provide an incentive for the power 

market to implement the shift in 

generation from coal to gas.755


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64819 

reduction measures reflected in the BSER and 

together produce an achievable compliance 

framework for sources. 

756See CO2 Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule for an 

illustration of this step. The EPA defined the 

‘‘incremental NGCC generation’’ in this step in a 

manner consistent with its measurement and use 

described in section VIII of this preamble. 

757See CO2 Emission Performance Rate and Goal 

Computation TSD for CPP Final Rule for an 

illustration of this step. We note that the entire 

NGCC generation level (inclusive of the amount 

assigned to the fossil steam rate) expected post 

building block application is included in the NGCC 

rate calculation. Including the entire NGCC 

generation in the NGCC rate recognizes the 

simultaneous compliance responsibility of affected 

NGCC units while the fossil steam rate recognizes 

its mitigation potential through incorporation of the 

incremental NGCC generation component. Failing 

to do so would result in a NGCC rate lower than 

that expected after full implementation of the 

building blocks and create a compliance 

inconsistency when reporting all generation. 

758At 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. 

Also as discussed above, it is 

important that the compliance equations 

reflect the BSER pro rata allocation of 

RE to fossil steam and NGCC generation. 

The first approach to define the quantity 

of NGCC generation and emission to be 

averaged into the steam rate would 

require the steam rate to take into 

account the total additional NGCC 

generation that results from the 

application of building block 3 before 

building block 2 has been applied. This 

approach would reflect in the 

compliance rate for steam units a greater 

share of the implementation of building 

block 3. Ensuring that emission 

performance rates for both steam and 

gas units reflect the emission reduction 

potential of building block 3 is integral 

to the building block 3 methodology and 

also recognizes that application of 

building block 3 on a pro-rata basis was 

intended to achieve emission reductions 

from both NGCC and fossil steam 

commensurate with their emissions 

reduction opportunities. 

If the EPA were to use the increment 

of NGCC emissions and generation 

derived at the intermediary step after 

the application of building block 3, 

rather than the increment relative to the 

2012 baseline, the effect would be to 

largely assign to fossil steam the 

building block 3 generation shift 

apportioned to NGCC. That, in turn, 

would have undermined the fact that 

building block 3 was determined to be 

a BSER measure applicable to the entire 

source category, comprising NGCC as 

well as fossil steam, and would have 

conflicted with the preceding steps we 

are taking to develop the equations. 

Instead, by using only the incremental 

NGCC generation relative to the 

baseline, the EPA has ensured that the 

logic behind the pro rata displacement 

of fossil generation by RE generation is 

reflected in the emission rates. Having 

established the appropriate way to 

measure the amount of incremental gas 

generation placed in the fossil steam 

rate, the EPA is able to calculate the 

subcategory-specific emission 

performance rates. For the numerator of 

the fossil steam rate, the EPA multiplied 

the remaining fossil steam generation 

(post-step six) by the fossil steam rate 

reflecting the heat rate improvement 

from building block 1 (step four). We 

then added in the emissions associated 

with the incremental NGCC generation 

from step six by multiplying the 

incremental NGCC generation as 

discussed above (difference between the 

baseline NGCC generation level and 

post-step six NGCC generation) by the 

baseline NGCC rate for that region.756

This constitutes the numerator of the 

fossil steam emission rate. 

For the fossil steam denominator, the 

EPA added the remaining fossil steam 

generation (post-step six), the 

incremental NGCC generation defined 

above, and the amount of zero emitting 

building block 3 MWhs apportioned to 

fossil steam generation in the region 

(step five). Dividing the fossil steam 

numerator described above by this fossil 

steam denominator resulted in a 

regional adjusted fossil steam rate 

reflecting the three building blocks. 

For the NGCC performance rate, the 

EPA calculated a numerator in a similar 

manner. First, we took the remaining 

NGCC generation (post step six) and 

multiplied it by the regional baseline 

NGCC rate to calculate the total 

emissions in the numerator. For the 

denominator, the EPA added the 

remaining NGCC generation (post step 

six) to the amount of zero-emitting 

building block 3 generation assigned to 

that technology in step five. Dividing 

the emissions by this total generation 

value (inclusive of the RE generation 

apportioned to NGCC) provided a 

regional adjusted NGCC rate.757

Step eight (determining the 

nationwide subcategory-specific 

emission performance rate). 

Following step seven, we evaluated 

the resulting adjusted fossil steam rates 

and NGCC rates for each region and 

identified the highest (least stringent) 

emission rate among the three regions 

for each technology category. This 

becomes the nationwide emission 

performance rate for that technology 

class. This ensures that the same rates 

are applied to facilities in each region 

and that these rates are achievable by 

facilities in all three regions. 

Finally, the EPA repeated steps four 

through eight for each year 2022– 

2030.758 The resulting annual rates vary 

because the amount of building block 2 

and 3 potential in each year varies. The 

rates for years 2022–2029 were averaged 

together to calculate an interim rate, and 

the 2030 value becomes the final 

emission performance rate for that year 

forward. As described in the 

corresponding TSD, the EPA rounded 

the interim and final subcategoryspecific emission performance rates up 

to the nearest integer to ensure that they 

did not slightly overstate BSER potential 

through use of conventional rounding. 

Unless otherwise stated, conventional 

rounding is used elsewhere during the 

calculation process. 

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 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64820 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

VII. State-Specific CO2 Goals 

A. Overview 

In section VI of this preamble, the 

EPA provides the methodology for 

computing subcategory-specific CO2

emission performance rates, based on 

the BSER. The subcategory-specific CO2

emission performance rates are the 

quantitative expression of the BSER as 

determined by the EPA. In this section, 

we provide state rate-based goals and 

mass-based goals that can be used in the 

alternative, by states, as an equivalent 

quantitative expression of the BSER in 

establishing standards of performance 

for affected EGUs in state plans. In this 

section, the EPA also describes reasons 

for providing state-specific rate-based 

goals and mass-based goals equivalent 

to the emission performance rates, 

supported by the many requests from 

commenters for the provision of these 

alternative expressions of the BSER 

established by the EPA. We further 

ensure this equivalence, and therefore 

reflection of the BSER, by requiring that 

rate-based state goals and mass-based 

state goals fully implement the BSER, 

including by ensuring that affected 

EGUs operating under mass-based 

emission standards are not incented by 

dint of the mass-emissions constraint to 

shift generation to unaffected fossil fuelfired sources to an extent that deviates 

from, or negates, the implementation of 

the BSER. 

The EPA is reconstituting the 

emission performance rates discussed in 

section VI into statewide CO2 emission 

performance goals for each state for the 

purpose of facilitating states’ 

development of state plans 

encompassing maximum flexibilities in 

implementing the BSER. This statespecific goal is not a compliance 

requirement, but rather an alternative 

yet equivalent expression of the BSER 

that the state may choose to use to 

establish emission standards for its 

affected EGUs. The state goal is the 

equivalent of the technology-specific 

CO2 emission performance rates and 

represents the equivalent of the state’s 

applying the emission performance rates 

directly to its affected EGUs in the form 

of standards of performance. As 

discussed further in section VIII on state 

plans, the states are charged with setting 

emission standards for the affected 

EGUs in their respective jurisdictions 

such that the affected EGUs operating 

under those standards together satisfy 

the requirements of the final emission 

guidelines and statute by meeting the 

emission performance rates or 

equivalent statewide emission 

performance goals, and thereby meet 

emission standards that reflect the 

BSER. 

In the June 2014 proposal, the EPA 

proposed a set of state-specific emission 

rate-based CO2 goals (in lbs of CO2 per 

MWh of electricity generated). In 

addition, the EPA proposed emission 

rate-based CO2 goals for areas of Indian 

country and U.S. territories with 

affected EGUs in a supplemental 

proposal on November 4, 2014. To 

provide flexibility to states, territories, 

tribes and implementing authorities, the 

proposals authorized each 

implementing authority to translate the 

form of the goal to a mass-based form 

(i.e., goals expressed in terms of total 

tons of CO2 per year from affected 

EGUs), as long as the translated goal was 

equivalent to the rate-based goal. Upon 

issuance of the proposed rule, the EPA 

continued the extensive outreach effort 

to stakeholders and members of the 

public that the EPA had engaged in for 

many months preceding the proposal. 

We also issued a notice of data 

availability (79 FR 67406, November 13, 

2014) and technical support document 

(Docket ID: EPA–HQ–OAR–2013–0602– 

22187) to further clarify potential 

methods for the translation to a massbased equivalent. The outreach 

provided additional opportunities for all 

jurisdictions with affected EGUs—both 

individually and in regional groups—as 

well as numerous industry groups and 

non-governmental organizations, to 

meet with the EPA and ask clarifying 

questions about, and give initial 

reactions to, the proposed components, 

requirements and timing of the 

rulemaking. As a result of the outreach 

and notice of data availability, the EPA 

received informed substantive 

comments for the EPA to consider for 

the final rule. 

Numerous commenters encouraged 

and supported the EPA’s efforts to allow 

states the maximum possible degree of 

flexibility in developing plans for their 

affected EGUs, either as a mass-based or 

rate-based CO2 goal. States and other 

stakeholders supported the option to 

translate rate-based goals to mass-based 

goals for state plans and requested a 

simple and transparent method for 

determining mass-based statewide CO2

goals that are equivalent to statewide 

rate-based CO2 goals and thus reflective 

of the BSER. We received substantial 

comments on the potential 

methodologies for the translation of 

rate-based goals to mass-based goals. 

Several commenters requested that the 

EPA provide the translation to a 

statewide mass-based goals directly 

while others requested flexibility to 

translate to mass using a variety of 

methodologies and tools. In the context 

of these comments, the EPA has 

considered the appropriateness of ratebased and mass-based goals as an 

expression of BSER and their 

equivalence to the quantitative 

expression of BSER through the two CO2

emission performance rates. 

Based on the comments received, the 

EPA is providing a straightforward 

translation methodology from the CO2

emission performance rates to yield 

statewide rate-based and mass-based 

CO2 emission performance goals 

described in this section. The EPA is 

providing state mass-based goals in this 

final rule in place of having states 

determine the mass themselves. The 

mass-based goals are the result of a 

mathematical derivation that provides 

goals that are an equivalent expression 

of the BSER. Section VIII below 

discusses mechanisms for states to plan 

for and demonstrate achievement of the 

statewide CO2 emission performance 

goals. 

CAA section 111(d) requires states to 

submit a plan that establishes standards 

of performance for affected EGUs that 

implement the BSER. States meet the 

statutory requirements of CAA section 

111(d) and the requirements of the final 

emission guidelines by submitting 

emission standards for affected EGUs 

that meet the performance rates, which 

reflect the application of the BSER as 

determined by the EPA. Therefore, as a 

first step for states that choose to submit 

plans that meet the rate-based or massbased goals, the goals must be 

determined to have equivalence as an 

application of the BSER. For the ratebased and mass-based state goals 

provided here, this equivalence is 

evident in the mathematical derivation 

of the goals, as is described in sections 

VII.B and VII.C below. 

Further (as described in section 

VIII.J), the state plan must demonstrate 

that it has measures in place to ensure 

that any alternative to the performance 

rates (i.e., rate-based or mass-based state 

goals that it uses to establish standards 

of performance) does not result in 

affected EGUs’ failing to implement 

either the BSER measure themselves or 

alternative methods of compliance with 

emission standards that achieve 

equivalent reductions in emissions or 

carbon intensity. The EPA has identified 

one way in which affected EGUs could 

fail to meet, at a minimum, of the 

emission performance levels that would 

result from implementing the BSER, 

which state plans must do. 

Specifically, the EPA has determined 

that the three building blocks are the 

BSER, including shifting generation 

from an affected EGU to a loweremitting affected EGU or to a nonVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00160 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64821 

759See Chapter 3 of the Regulatory Impact 

Analysis for more information on this analysis, 

which is available in the docket. 

760The specific mass-based plan requirements are 

explained in detail in section VIII.J. 

emitting EGU and that states are 

required to establish standards of 

performance that require affected EGUs 

to achieve, at a minimum, the emission 

performance levels that reflect the BSER 

(recognizing that affected sources may 

choose from a range of equivalent 

actions (e.g., undertaking the measures 

included in the building blocks, shifting 

generation to low-emitting or zeroemitting resources not included in the 

building blocks or achieving demandside EE or transmission efficiency— 

either through operational undertakings, 

direct investment or emissions trading). 

Substantial shifting of generation from 

affected EGUs to new fossil fuel-fired 

EGUs, such as new NGCC units, 

represents a deviation from 

implementing the BSER or its 

compliance equivalent. 

Since the two subcategory-specific 

emission performance rates represent 

the BSER, states that established 

standards of performance at or below 

those rates, by definition, would be 

implementing state plans that created 

no risk that affected EGUs would shift 

generation to new fossil-fired EGUs to 

an extent that would deviate from the 

BSER. Similarly, the EPA has 

determined that states using rate-based 

goals as the foundation for plans 

implementing the BSER are unlikely to 

foster generation shifts to new fossil 

fuel-fired sources to an extent that 

would deviate from the BSER. In 

contrast, however, EPA analysis has 

identified a concern that a mass-based 

state plan that failed to include 

appropriate measures to address leakage 

could result in failure to achieve 

emission performance levels consistent 

with the BSER.759 Section VII.B 

describes how the form of the rate-based 

state goals minimizes the risk of 

generation shifts to new fossil fuel-fired 

sources, or ‘‘leakage,’’ by providing 

affected EGUs with a sufficient 

incentive to run, similar to the 

performance rates. Section VII.D. 

discusses how there is a potential for 

leakage under mass-based state goals 

because affected EGUs are incented to 

operate in a manner—in particular, by 

shifting generation to new NGCC units 

(as opposed to shifting generation as 

contemplated by the BSER or 

undertaking equivalent alternative 

compliance actions)—that would result 

in negating the equivalence with the 

emission performance rates and thus the 

BSER, and specifies that requirements 

are needed in mass-based 

implementation to assure those 

incentives are realigned.760

B. Reconstituting Statewide Rate-Based 

CO2 Emission Performance Goals From 

the Subcategory-Specific Emission 

Performance Rates 

In order to provide states flexibility 

for planning purposes, the EPA is 

providing a state-specific averaging of 

the subcategory-specific emission 

performance rates to determine a 

statewide goal. While the emission 

performance rates reflect the 

quantification of performance based on 

the BSER and embody the reductions 

estimated under building blocks 1, 2, 

and 3, the state goals reflect an 

equivalent approach through which 

states may choose to adopt and 

implement those subcategory-specific 

performance rates. 

The EPA quantified the potential 

reductions of the BSER in the 

subcategory-specific emission 

performance rates established in section 

VI. These rates themselves reflect the 

reduction potential expected in 

emission rates under the BSER for each 

year from 2022 to 2030. To establish 

state goals, the EPA applied these rates 

to the baseline generation levels to 

estimate the affected fleet emission rate 

that would occur if all affected EGUs in 

the fleet met the subcategory-specific 

rates. This step respects the flexibility of 

sources to meet the rates in any manner 

that they see fit (e.g., on-site abatement 

technology, fuel switching, co-firing, 

credit purchase, etc.), and does not limit 

them to their building block 

assumptions. For example, the EPA 

derived the statewide rate-based CO2

emission performance goals for 2030 by 

multiplying the fossil steam emission 

performance rate for 2030 by the 

baseline fossil steam generation in a 

state and multiplying the NGCC 

emission performance rate for 2030 by 

the baseline NGCC generation in a state. 

The resulting emissions for fossil steam 

and NGCC are then added together for 

each state. This emission total is 

divided by that state’s baseline 

generation values from the likely 

affected EGUs in order to develop a 

state’s rate-based CO2 emission 

performance goal for 2030. This blended 

rate reflects the collective emission rate 

a state may expect to achieve when its 

baseline fleet of likely affected EGUs 

continues to operate at baseline levels 

while meeting its subcategory-specific 

emission performance rates reflecting 

the BSER. The EPA believes that using 

the adjusted 2012 baseline is the most 

appropriate way to combine the rates. 

First, as explained in Section VI, the 

EPA believes there are significant 

advantages to using real world data to 

set a baseline rather than using 

projected data. The adjusted 2012 data 

is the logical starting point because it is 

the data that all of the emission 

performance rates (discussed in Section 

VI) are based upon. Furthermore, it is 

clear that generation shifts as projected 

under the BSER are not the appropriate 

baseline. The emission performance 

rates already factor in the BSER 

assumptions about changes in 

generation (e.g., implementation of 

building block 2 significantly lowers the 

emission performance rate for fossilsteam units). If, on top of that, changes 

in generation were factored into the 

calculation of a combined rate, those 

changes in generation would be factored 

into the combined rate twice (once 

when calculating the individual 

emission performance rates and a 

second time, when incorporating those 

rates into a combined state rate). 

This step is repeated for each year 

from 2022–2029 using the emission 

performance rates calculated for each of 

those years in the previous section. The 

EPA also repeats this step for the 

interim state goal using the interim 

subcategory rates. The EPA then 

averages together the annual amounts in 

increments of 3 years, 3 years, and 2 

years for 2022–2024, 2025–2027, and 

2028–2029 to estimate emission rate 

averages for those periods that can 

provide one illustrative pathway for 

states to consider in meeting their 

interim goals. These 3- and 2-year 

increment are not regulatory guidelines 

or equivalents for interim goals, but 

rather benchmarks for demonstrating 

plan performance as discussed in 

Section VIII.F illustrative of a potential 

gradual reduction compliance strategy 

that states may use to reach their 

interim and final state goals. 

As described in the steps above, the 

statewide goals represent an equivalent 

arithmetic combination of the 

subcategory-specific emission 

performance rates, weighted by the 

historical baseline generation levels 

upon which the BSER is premised. In 

particular, as discussed above, the 

method for deriving these goals assures 

equivalent flexibility by applying the 

CO2 emission performance rates to the 

baseline levels, which respects the 

flexibility of affected EGUs to meet the 

rates in whatever way they wish. This 

corresponding treatment of affected 

EGUs based on the adjusted 2012 

baseline ensures sufficient incentive to 

affected existing EGUs to generate and 

thus avoid leakage, similar to the CO2


tkelley on DSK3SPTVN1PROD with BOOK 2
64822 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

761For more detail on this methodology, please 

refer to the CO2 Emission Performance Rate and 

Goal Computation TSD for CPP Final Rule, which 

is available in the docket. 

762The final rule includes state plan conditions 

to prevent perverse incentives that could otherwise 

result in greater overall emissions when generation 

shifts across affected EGUs. For example, states that 

wish to engage in rate-based trading through an 

emission standards plan type must adopt plans 

designed to achieve either a common rate-based 

state goal or the subcategory-specific emission 

performance rates (see section VIII.L). Such a state 

plan condition avoids encouraging generation to 

shift from a state with a relatively lower state goal 

to a state with a relatively higher state goal solely 

as a response to the form of CPP implementation. 

emission performance rates (this is 

further discussed in section VII.D 

below). Consequently, the statewide 

goals are equivalent to the CO2 emission 

performance rates and are thus an 

equivalent expression of the BSER. The 

rate-based statewide goals are provided 

below in Table 12. 

C. Quantifying Mass-Based CO2

Emission Performance Goals From the 

Statewide Rate-Based CO2 Emission 

Performance Goals 

The EPA is also establishing massbased statewide CO2 emission 

performance goals for each state, which 

are provided below in Table 13. For 

state plans choosing to meet a massbased goal, such a goal must be 

equivalent to the CO2 emission 

performance rates in their application of 

the BSER, as required by the statute and 

the final emission guidelines. In the 

following discussion we describe the 

mathematical calculations that provide 

an equivalent expression of the BSER. In 

evaluating the equivalence of the form 

of mass goals, the EPA must also 

recognize the impact that the form of the 

standard has on the relative incentives 

that the implementation of these goals 

provides to affected and unaffected 

EGUs. This section specifies how we 

have established a quantitative basis for 

mass goals that is equivalent to CO2

emission performance rates. The next 

section (section VII.D) specifies how we 

require state plans to ensure 

equivalence to the CO2 emission 

performance rates through certain 

requirements that realign the potential 

difference in incentives provided to 

affected and unaffected EGUs to 

generate under a mass-based 

implementation compared to a ratebased implementation that could result 

in leakage. 

The starting place for quantifying 

mass-based statewide CO2 emission 

performance goals is the emission 

amounts directly represented in the 

numerator of the statewide rate-based 

CO2 emission performance goals. Each 

state-specific emission amount is the 

product of the fossil steam emission 

performance rate and historical fossil 

steam generation, added to the product 

of the NGCC emission performance rate 

and historical NGCC generation. The 

resulting emission amounts for each 

state represent the emissions associated 

with rate-based compliance at historical 

generation levels. 

However, under a rate-based state 

plan, all affected EGUs have the 

opportunity to increase utilization, 

provided that sufficient emission 

reduction measures are available to 

maintain the necessary ratio of 

emissions to generation as quantified by 

the subcategory-specific emission 

performance rates. Due to the nature of 

the emission performance rate 

methodology, which selects the highest 

of the three interconnection-based 

values for each source category as the 

CO2 emission performance rate, there 

are cost-effective lower-emitting 

generation opportunities quantified 

under the building blocks that are not 

necessary for affected EGUs in the 

Western and Texas interconnections to 

demonstrate compliance at historical 

generation levels. The EPA recognizes 

that these lower-emitting generation 

opportunities are available to affected 

EGUs at a national level as a means to 

increase their own output (and, as a 

result, their own emissions) while 

maintaining the relevant emission 

performance rate. To afford affected 

EGUs subject to a mass-based goal 

similar compliance flexibility as EGUs 

subject to a rate-based goal, the EPA has 

quantified the emissions associated with 

the potential realization of these loweremitting generation opportunities and 

incorporated those additional tons into 

each state’s mass-based goal.761 Because 

the derivation of these mass-based goals 

respects the arithmetic of the 

subcategory-specific emission 

performance rates and the flexibility of 

affected EGUs to achieve those rates 

while utilizing up to the full potential 

quantified in the building blocks, the 

derivation of these mass-based state 

goals offers an equivalent expression of 

BSER in mass form. 

The mass goals for existing sources 

are presented in Table 13. Although 

their derivation is equivalent to the 

subcategory-specific emission 

performance rates, in order to maintain 

this equivalence in the establishment of 

emission standards in state plans mass 

goals must be implemented in 

combination with requirements that 

align the incentives provided to affected 

and unaffected EGUs, specifically in 

order to prevent leakage. 

D. Addressing Potential Leakage in 

Determining the Equivalence of StateSpecific CO2 Emission Performance 

Goals 

As described in section VI, the 

subcategory-specific emission 

performance rates reflect the BSER as 

determined by the EPA. This final rule 

allows states to establish emission 

standards that meet either rate-based or 

mass-based state goals. As stated above, 

rate-based state goals were published in 

the proposed rule, and commenters not 

only supported having the flexibility to 

use rate-based goals or mass-based goals 

as part of state plans, but also requested 

that the EPA include mass-based goals 

in this final rule. But to ensure the 

equivalence of mass-based state goals, 

we must consider how the form of the 

goal affects its implementation and how 

the incentives it provides to affected 

EGUs on the interstate grid affect 

whether or not the BSER is fully 

implemented. 

Because of the integrated nature of the 

utility power sector, the form of the 

emission performance requirements for 

existing sources may ultimately impact 

the relative incentives to generate and 

emit at affected EGUs as opposed to 

shifting generation to new sources, with 

potential implications for whether a 

given set of standards of performance is, 

at a minimum, consistent with the 

BSER, in the context of overall 

emissions from the sector. In this 

context, we, again, define as ‘‘leakage’’ 

the potential of an alternative form of 

implementation of the BSER (e.g., the 

rate-based and mass-based state goals) to 

create a larger incentive for affected 

EGUs to shift generation to new fossil 

fuel-fired EGUs relative to what would 

occur when the implementation of the 

BSER took the form of standards of 

performance incorporating the 

subcategory-specific emission 

performance rates representing the 

BSER. In the proposal, the EPA 

recognized that the statutory 

construction regarding the BSER is to 

reduce emissions, which can be 

achieved through shifts of generation. 

Movement of generation between and 

among sources is needed to produce 

overall reductions, particularly 

movement from higher-emitting affected 

EGUs to lower-emitting affected EGUs, 

and from all affected EGUs to zeroemitting RE. In all of these cases, the 

fossil sources involved in these 

generation shifts are subject to 

obligations under this final rule.762

However, leakage, where shifts in 

generation to unaffected fossil fuel-fired 

sources result in increased emissions, 

relative to what would have happened 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64823 

763See Chapter 3 of the Regulatory Impact 

Analysis for more information on this analysis, 

which is available in the docket. 

had generation shifts consistent with the 

BSER occurred, is contrary to this 

construction. Therefore, if the form of 

the standard does not address leakage or 

incents the kinds of generation shifts 

that we identify as leakage, the states 

must otherwise address leakage in order 

to ensure that the standards of 

performance applied to the affected 

EGUs are, in the aggregate, at least 

equivalent with the emission 

performance rates, and therefore 

appropriately reflect the BSER as 

required by the statute. Commenters 

noted that shifting generation and 

emissions from existing sources to new 

sources undermined the intent of this 

rule and the overall emission reduction 

goals, and that requiring states to 

address leakage is consistent with the 

obligation that states establish standards 

of performance that, in the aggregate, at 

a minimum, reflect the BSER for 

affected EGUs operating in the 

interconnected electricity sector. 

This section specifically addresses the 

need for state plans designed to achieve 

either rate- or mass-based state goals to 

ensure that their plans succeed in 

implementing standards of performance 

that reflect the BSER by minimizing the 

difference in incentives provided to 

affected EGUs and new sources to 

generate in order to maintain equivalent 

emission performance with the CO2

emission performance rates. 

Rate-based goals do not in our view 

implicate leakage to an extent that 

would negate or limit the 

implementation of the BSER because 

under a rate-based state goal, similar to 

the subcategory-specific emission 

performance rates, existing loweremitting affected EGUs, primarily NGCC 

units, are incentivized to increase their 

utilization in order to improve the 

average emission rates of affected EGUs 

overall. New units that are not subject 

to the rate-based state goal, and that are 

not an allowable measure for adjusting 

an EGU’s CO2 emission rate, will not 

have this incentive to increase 

utilization, and as a result, the 

imposition of a rate-based goal on 

affected EGUs is unlikely to encourage 

increased generation and emissions 

from unaffected new EGUs. The form of 

the rate-based state goals provides an 

equivalent or greater incentive to 

affected existing EGUs as they are 

provided in the CO2 emission 

performance rates, and similarly avoid 

the potential for leakage. Under both 

approaches, existing NGCC units can 

generate ERCs. These ERCs provide an 

economic incentive to utilize existing 

NGCC units rather than new NGCC 

units. Further, ERCs from incremental 

RE incentivize new renewable 

generation over new NGCC generation. 

Both of these features, which exist in 

the context of implementation with a 

state rate-based goal or CO2 emission 

performance rates, provide significant 

incentives to ensure that, consistent 

with the BSER, shifting of generation 

does not occur between existing fossil 

fuel-fired units and new NGCC units. 

Mass-based goals for existing sources, 

however, incur a leakage risk to the 

extent that they incent generation shifts 

from affected EGUs to unaffected fossil 

fuel-fired sources in a way that negates 

the reliance on the BSER. In contrast to 

various forms of rate-based 

implementation, mass-based 

implementation in a state plan can 

unintentionally incentivize increased 

generation from unaffected new EGUs as 

a substitute action for reducing 

emissions at units subject to the existing 

source mass goal in ways that would 

negate the implementation of the BSER 

and would result in increased 

emissions. This occurs because, unlike 

in a rate-based system where rate-based 

averaging lowers the cost of generation 

from existing NGCC units relative to 

generation from new NGCC units, in a 

mass-based system the allowance price 

increases the cost of generation from 

existing NGCC units relative to 

generation from new NGCC units. The 

extent to which electricity providers opt 

to rely on this increase in unaffected 

new source utilization as a substitute for 

improving the emissions performance 

across existing sources would be 

fundamentally inconsistent with relying 

on the BSER to reduce emissions as the 

basis of the subcategory-specific 

emission performance rates. 

As a result, notwithstanding the fact 

that mass goals for existing sources are 

quantified in a way that is an equivalent 

expression of the BSER, the form of 

mass goals is only equivalent if leakage 

is satisfactorily addressed in the state 

plan’s establishment of emission 

standards and implementation 

measures. The EPA is therefore 

requiring that states adopting a massbased state plan include requirements 

that address leakage, or otherwise 

provide additional justification that 

leakage would not occur under the 

state’s implementation of mass-based 

emission standards. This requirement 

enables states to establish standards of 

performance that meet a mass-based 

goal equivalent to the performance rates 

and therefore reflect the BSER, as 

required by section 111(d). The required 

demonstration and options for state 

plans to minimize leakage are discussed 

in detail in section VIII.J of this 

preamble. 

Further supporting the need for this 

requirement, the EPA has evaluated the 

mass goals in concert with some of the 

options to minimize leakage described 

in that section. As mentioned above, the 

EPA analysis identified a concern 

regarding leakage in a mass-based 

approach, namely that the mass-based 

implementation without measures to 

address leakage produced higher 

generation from new NGCC units and 

lower emission performance when 

compared to a rate-based 

implementation. Further analysis where 

implementation of the mass-based goals 

was coupled with measures to address 

leakage produce utility power sector 

emissions performance that is similar to 

emissions performance under the rate 

goals.763

E. State Plan Adjustments of State Goals 

The EPA notes that it is the emission 

performance rates in section VI that 

constitute the application of the BSER to 

the affected EGUs and serve as the chief 

regulatory requirement of this 

rulemaking. The statewide CO2 ratebased and mass-based emission 

performance goals provided here are 

metrics that states may choose to adopt 

when demonstrating compliance at the 

state level, and states may consider 

these goals when determining how to 

set unit-level compliance requirements. 

The EPA believes that the regional 

nature of determining the emission 

performance rates encompasses a large 

population size and makes it robust 

against unit-level variation and unitlevel inventory discrepancies. The EPA 

does acknowledge that state-level ratebased goals or mass-based goals may be 

sensitive to applicability changes within 

a state’s affected population. In the 

proposal, the EPA used a baseline that 

aggregated data for what it believed to 

be affected units and asked states, 

companies and other stakeholders to 

provide corrections in their comments. 

We received input from many 

commenters and have corrected 

information as appropriate. Therefore, 

we believe the baseline to be accurate. 

However, if subsequent applicability 

review or formal applicability 

determinations change the status of 

units in regards to being affected or 

unaffected by this rulemaking, states 

can, via state plan submittal or revision, 

adjust their statewide rate or mass goal 

to reflect this change of status. 

This adjustment flexibility provision 

is based on comments received at 

proposal. For example, some 


tkelley on DSK3SPTVN1PROD with BOOK 2
64824 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

764The EPA has not developed statewide ratebased or mass-based CO2 emission performance 

goals for Vermont and the District of Columbia because current information indicates those 

jurisdictions have no affected EGUs. 

stakeholders noted that the affected 

status of particular units was unclear. 

The EPA recognizes that all the 

necessary data to determine the affected 

status of some units may not be 

available at this time. As stated above, 

the EPA does not believe unit-level 

variation or inclusion/exclusion 

disparities between baseline inventory 

and affected units will impact the 

regionally determined emission 

performance rates discussed in the 

previous section. However, variations in 

baseline data or inventory may have an 

impact on the state-level rate-based or 

mass-based goals provided in this 

section. Therefore, the EPA is allowing 

the flexibility for states to demonstrate 

the need for this type of adjustment 

under the justifications above and 

utilize an adjusted value for compliance 

purposes when submitting or revising 

its state plan. The EPA will evaluate the 

appropriateness of such an adjusted 

value based on the state’s demonstration 

and evaluate the approvability of a plan 

or plan revision accordingly. 

Rate-based statewide CO2 emission 

performance goals are listed below in 

Table 12. Mass-based statewide CO2

emission performance goals are found in 

Table 13. 

TABLE 12—STATEWIDE 764 RATE-BASED CO2 EMISSION PERFORMANCE GOALS

[Adjusted output-weighted-average pounds of CO2 per net MWh from all affected fossil fuel-fired EGUs] 

State name Interim goal— 

Step 1 

Interim goal— 

Step 2 

Interim goal— 

Step 3 Interim goal Final goal 

Alabama ................................................. 1,244 1,133 1,060 1,157 1,018 

Arizona * ................................................. 1,263 1,149 1,074 1,173 1,031 

Arkansas ................................................ 1,411 1,276 1,185 1,304 1,130 

California ................................................ 961 890 848 907 828 

Colorado ................................................ 1,476 1,332 1,233 1,362 1,174 

Connecticut ............................................ 899 836 801 852 786 

Delaware ................................................ 1,093 1,003 946 1,023 916 

Florida .................................................... 1,097 1,006 949 1,026 919 

Georgia .................................................. 1,290 1,173 1,094 1,198 1,049 

Idaho ...................................................... 877 817 784 832 771 

Illinois ..................................................... 1,582 1,423 1,313 1,456 1,245 

Indiana ................................................... 1,578 1,419 1,309 1,451 1,242 

Iowa ....................................................... 1,638 1,472 1,355 1,505 1,283 

Kansas ................................................... 1,654 1,485 1,366 1,519 1,293 

Kentucky ................................................ 1,643 1,476 1,358 1,509 1,286 

Lands of the Fort Mojave Tribe ............. 877 817 784 832 771 

Lands of the Navajo Nation ................... 1,671 1,500 1,380 1,534 1,305 

Lands of the Uintah and Ouray Reservation ............................................... 1,671 1,500 1,380 1,534 1,305 

Louisiana ................................................ 1,398 1,265 1,175 1,293 1,121 

Maine ..................................................... 888 827 793 842 779 

Maryland ................................................ 1,644 1,476 1,359 1,510 1,287 

Massachusetts ....................................... 956 885 844 902 824 

Michigan ................................................. 1,468 1,325 1,228 1,355 1,169 

Minnesota .............................................. 1,535 1,383 1,277 1,414 1,213 

Mississippi .............................................. 1,136 1,040 978 1,061 945 

Missouri .................................................. 1,621 1,457 1,342 1,490 1,272 

Montana ................................................. 1,671 1,500 1,380 1,534 1,305 

Nebraska ................................................ 1,658 1,488 1,369 1,522 1,296 

Nevada ................................................... 1,001 924 877 942 855 

New Hampshire ..................................... 1,006 929 881 947 858 

New Jersey ............................................ 937 869 829 885 812 

New Mexico * ......................................... 1,435 1,297 1,203 1,325 1,146 

New York ............................................... 1,095 1,005 948 1,025 918 

North Carolina ........................................ 1,419 1,283 1,191 1,311 1,136 

North Dakota .......................................... 1,671 1,500 1,380 1,534 1,305 

Ohio ....................................................... 1,501 1,353 1,252 1,383 1,190 

Oklahoma ............................................... 1,319 1,197 1,116 1,223 1,068 

Oregon ................................................... 1,026 945 896 964 871 

Pennsylvania .......................................... 1,359 1,232 1,146 1,258 1,095 

Rhode Island .......................................... 877 817 784 832 771 

South Carolina ....................................... 1,449 1,309 1,213 1,338 1,156 

South Dakota ......................................... 1,465 1,323 1,225 1,352 1,167 

Tennessee ............................................. 1,531 1,380 1,275 1,411 1,211 

Texas ..................................................... 1,279 1,163 1,086 1,188 1,042 

Utah * ..................................................... 1,483 1,339 1,239 1,368 1,179 

Virginia ................................................... 1,120 1,026 966 1,047 934 

Washington ............................................ 1,192 1,088 1,021 1,111 983 

West Virginia .......................................... 1,671 1,500 1,380 1,534 1,305 

Wisconsin ............................................... 1,479 1,335 1,236 1,364 1,176 

Wyoming ................................................ 1,662 1,492 1,373 1,526 1,299 

* Excludes EGUs located in Indian country within the state. 


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765Hawaii Solar Integration Study, NREL 

Technical Report NREL/TP–5500–57215, June 2013. 

Available at http://www.nrel.gov/docs/fy13osti/

57215.pdf. 

TABLE 13—STATEWIDE MASS-BASED CO2 EMISSION PERFORMANCE GOALS

[Adjusted output-weighted-average tons of CO2 from all affected fossil fuel-fired EGUs] 

State Interim goal— 

Step 1 

Interim goal— 

Step 2 

Interim goal— 

Step 3 Interim goal Final goal 

Alabama ................................................. 66,164,470 60,918,973 58,215,989 62,210,288 56,880,474 

Arizona* ................................................. 35,189,232 32,371,942 30,906,226 33,061,997 30,170,750 

Arkansas ................................................ 36,032,671 32,953,521 31,253,744 33,683,258 30,322,632 

California ................................................ 53,500,107 50,080,840 48,736,877 51,027,075 48,410,120 

Colorado ................................................ 35,785,322 32,654,483 30,891,824 33,387,883 29,900,397 

Connecticut ............................................ 7,555,787 7,108,466 6,955,080 7,237,865 6,941,523 

Delaware ................................................ 5,348,363 4,963,102 4,784,280 5,062,869 4,711,825 

Florida .................................................... 119,380,477 110,754,683 106,736,177 112,984,729 105,094,704 

Georgia .................................................. 54,257,931 49,855,082 47,534,817 50,926,084 46,346,846 

Idaho ...................................................... 1,615,518 1,522,826 1,493,052 1,550,142 1,492,856 

Illinois ..................................................... 80,396,108 73,124,936 68,921,937 74,800,876 66,477,157 

Indiana ................................................... 92,010,787 83,700,336 78,901,574 85,617,065 76,113,835 

Iowa ....................................................... 30,408,352 27,615,429 25,981,975 28,254,411 25,018,136 

Kansas ................................................... 26,763,719 24,295,773 22,848,095 24,859,333 21,990,826 

Kentucky ................................................ 76,757,356 69,698,851 65,566,898 71,312,802 63,126,121 

Lands of the Fort Mojave Tribe ............. 636,876 600,334 588,596 611,103 588,519 

Lands of the Navajo Nation ................... 26,449,393 23,999,556 22,557,749 24,557,793 21,700,587 

Lands of the Ute Tribe of the Uintah 

and Ouray Reservation ...................... 2,758,744 2,503,220 2,352,835 2,561,445 2,263,431 

Louisiana ................................................ 42,035,202 38,461,163 36,496,707 39,310,314 35,427,023 

Maine ..................................................... 2,251,173 2,119,865 2,076,179 2,158,184 2,073,942 

Maryland ................................................ 17,447,354 15,842,485 14,902,826 16,209,396 14,347,628 

Massachusetts ....................................... 13,360,735 12,511,985 12,181,628 12,747,677 12,104,747 

Michigan ................................................. 56,854,256 51,893,556 49,106,884 53,057,150 47,544,064 

Minnesota .............................................. 27,303,150 24,868,570 23,476,788 25,433,592 22,678,368 

Mississippi .............................................. 28,940,675 26,790,683 25,756,215 27,338,313 25,304,337 

Missouri .................................................. 67,312,915 61,158,279 57,570,942 62,569,433 55,462,884 

Montana ................................................. 13,776,601 12,500,563 11,749,574 12,791,330 11,303,107 

Nebraska ................................................ 22,246,365 20,192,820 18,987,285 20,661,516 18,272,739 

Nevada ................................................... 15,076,534 14,072,636 13,652,612 14,344,092 13,523,584 

New Hampshire ..................................... 4,461,569 4,162,981 4,037,142 4,243,492 3,997,579 

New Jersey ............................................ 18,241,502 17,107,548 16,681,949 17,426,381 16,599,745 

New Mexico* .......................................... 14,789,981 13,514,670 12,805,266 13,815,561 12,412,602 

New York ............................................... 35,493,488 32,932,763 31,741,940 33,595,329 31,257,429 

North Carolina ........................................ 60,975,831 55,749,239 52,856,495 56,986,025 51,266,234 

North Dakota .......................................... 25,453,173 23,095,610 21,708,108 23,632,821 20,883,232 

Ohio ....................................................... 88,512,313 80,704,944 76,280,168 82,526,513 73,769,806 

Oklahoma ............................................... 47,577,611 43,665,021 41,577,379 44,610,332 40,488,199 

Oregon ................................................... 9,097,720 8,477,658 8,209,589 8,643,164 8,118,654 

Pennsylvania .......................................... 106,082,757 97,204,723 92,392,088 99,330,827 89,822,308 

Rhode Island .......................................... 3,811,632 3,592,937 3,522,686 3,657,385 3,522,225 

South Carolina ....................................... 31,025,518 28,336,836 26,834,962 28,969,623 25,998,968 

South Dakota ......................................... 4,231,184 3,862,401 3,655,422 3,948,950 3,539,481 

Tennessee ............................................. 34,118,301 31,079,178 29,343,221 31,784,860 28,348,396 

Texas ..................................................... 221,613,296 203,728,060 194,351,330 208,090,841 189,588,842 

Utah* ...................................................... 28,479,805 25,981,970 24,572,858 26,566,380 23,778,193 

Virginia ................................................... 31,290,209 28,990,999 27,898,475 29,580,072 27,433,111 

Washington ............................................ 12,395,697 11,441,137 10,963,576 11,679,707 10,739,172 

West Virginia .......................................... 62,557,024 56,762,771 53,352,666 58,083,089 51,325,342 

Wisconsin ............................................... 33,505,657 30,571,326 28,917,949 31,258,356 27,986,988 

Wyoming ................................................ 38,528,498 34,967,826 32,875,725 35,780,052 31,634,412 

* Excludes EGUs located in Indian country within the state. 

F. Geographically Isolated States and 

Territories With Affected EGUs 

Alaska, Hawaii, Guam, and Puerto 

Rico constitute a small set of states and 

U.S. territories representing about one 

percent of total U.S. EGU GHG 

emissions. Based on the current record, 

the EPA does not possess all of the 

information or the analytic tools needed 

to quantify the application of the BSER 

for these states and territories, 

particularly data regarding RE costs and 

performance characteristics needed for 

building block 3 of the BSER. The NREL 

data for RE that the EPA is relying upon 

for building block 3 does not cover the 

non-contiguous states and territories. 

The EPA acknowledges that NREL has 

collaborated with the state of Hawaii to 

provide technical expertise in support 

of the state’s aggressive goals for clean 

energy, including analyses of the grid 

integration and transmission of solar 

and wind resources.765 The EPA also 

recognizes that there are studies and 

data for some renewable resources in 

some of the other non-contiguous 

jurisdictions. However, taken as a 

whole, the data we currently possess do 

not allow us to quantify the emissions 

reductions available from building block 

3 using the same methodology used for 


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766See, e.g., Grand Canyon Air Tour Coalition v. 

F.A.A., 154 F.3d 455, 471 (D.C. Cir. 1998) 

(ordinarily, agencies have wide latitude to attack a 

regulatory problem in phases and that a phased 

attack often has substantial benefits); National 

Association of Broadcasters v. FCC, 740 F.2d 1190, 

121–11 (D.C. Cir. 1984) (‘‘We have therefore 

recognized the reasonableness of [an agency’s] 

decision to engage in incremental rulemaking and 

to defer resolution of issues raised in a 

rulemaking. . . .’’). 

767As stated previously, states with one or more 

affected EGUs will be required to develop and 

implement plans that set emission standards for 

affected EGUs. The CAA section 111(d) emission 

guidelines that the EPA is promulgating in this 

action apply to only the 48 contiguous states and 

any Indian tribe that has been approved by the EPA 

pursuant to 40 CFR 49.9 as eligible to develop and 

implement a CAA section 111(d) plan. Because 

Vermont and the District of Columbia do not have 

affected EGUs, they will not be required to submit 

a state plan. 

the contiguous states encompassed by 

the three interconnections. Lastly, the 

IPM model used to support the EPA’s 

analysis is geographically limited to the 

contiguous U.S. As a result of these 

factors, the EPA currently lacks the 

necessary analytic resources to set 

emission performance goals for these 

areas. 

Because of the lack of suitable data 

and analytic tools needed to develop 

area-appropriate building block targets 

as defined in section V, the EPA is not 

setting CO2 emission performance goals 

for Alaska, Hawaii, Guam, or Puerto 

Rico in this final rule at this time. The 

EPA believes it is within its authority to 

address performance goals only for the 

contiguous U.S. states in this final rule. 

Under section 111(d), the EPA is not 

required, at the time that the EPA 

promulgates section 111(b) 

requirements for new sources, to 

promulgate emission guidelines for all 

of the sources that, if they were new 

sources, would be subject to the section 

111(b) requirements if there is a 

reasonable basis for deferring certain 

groups of sources. As discussed, in this 

rule, the EPA has a reasonable basis for 

deferring setting goals for these four 

jurisdictions. In addition, the Courts 

have recognized the authority of 

agencies to develop regulatory programs 

in step-by-step fashion. As the U.S. 

Supreme Court noted in Massachusetts 

v. EPA, 549 U.S. 497, 524 (2007): 

‘‘Agencies, like legislatures, do not 

generally resolve massive problems in 

one fell regulatory swoop;’’ and instead 

they may permissibly implement such 

regulatory programs over time, ‘‘refining 

their preferred approach as 

circumstances change and as they 

develop a more nuanced understanding 

of how best to proceed.’’ 766

The EPA recognizes, however, that 

EGUs in Alaska, Hawaii, Puerto Rico, 

and Guam emit CO2 and that there are 

opportunities to reduce the carbon 

intensity of generation in those areas 

over time. We recognize further that 

there are efforts underway to increase 

the use of RE in these jurisdictions. In 

particular, we recognize that Hawaii has 

tremendous opportunities for RE and 

has adopted very ambitious goals: 40 

percent clean energy by 2030 and 100 

percent by 2045. Since 2008, Alaska has 

apportioned in excess of $1.34 billion 

pursuing its aspirational goal of 50 

percent of the state’s total yearly electric 

load from renewable and alternative 

energy sources by 2025. Puerto Rico’s 

goal is to achieve 20 percent RE sales by 

2035, and the territory is working hard 

to meet the requirements of the Mercury 

and Air Toxics Standards, which will 

reduce emissions from its power plants 

substantially. Guam’s RPS is to achieve 

25 percent REsales by 2035. 

The agency intends to continue to 

consider these issues and determine 

what the appropriate BSER is for these 

areas. As part of that effort, the agency 

will investigate sources of information 

and types of analysis appropriate to 

devise the appropriate levels for 

building block 3 and BSER performance 

levels. Because we recognize that these 

areas face some of the most urgent 

climate change challenges, severe public 

health problems from air pollution and 

some of the highest electricity rates in 

the U.S., the EPA is committed to 

obtaining the right information to 

quantify the emission reductions that 

are achievable in these four areas and 

putting goals in place soon. 

VIII. State Plans 

A. Overview 

After the EPA establishes the 

emission guidelines that set forth the 

BSER, each state with one or more 

affected EGUs 767 shall then develop, 

adopt and submit a state plan under 

CAA section 111(d) that establishes 

standards of performance for the 

affected EGUs in its jurisdiction in order 

to implement the BSER. Starting from 

the foundation of CAA section 111(d) 

and the EPA’s implementing regulations 

(40 CFR part 60 subpart B), the EPA’s 

proposal laid out a number of options, 

variations and flexibilities that were 

intended to provide states and affected 

EGUs the ability to design state plans 

that accorded with states’ specific 

situations and policies (now and in the 

future), and to ensure reliability and 

affordability of electricity across the 

system and for all ratepayers. The 

proposal has prompted numerous 

discussions between and among 

stakeholders, especially states and 

groups of states, including state 

environmental and energy regulators 

and policy officials. The EPA has 

received many comments from a wide 

range of stakeholders seeking a final 

rule that afforded freedom and 

flexibility to consider a wide range of 

standards of performance to implement 

the BSER, but also providing significant 

feedback on the elements and options in 

the proposal and constructive 

suggestions for alternative approaches. 

The EPA has carefully considered all of 

this input, and is finalizing emission 

guidelines that continue to provide a 

variety of options for states to fashion 

their plans in ways legally supportable 

by the CAA, while also making certain 

adjustments to address key comments. 

The next few paragraphs present an 

overview of the main features of the 

final emission guidelines, highlighting 

key changes from proposal. In the rest 

of this section, we describe in detail the 

various elements of the final emission 

guidelines’ requirements for state plans. 

The proposal contained rate-based 

goals for each state, reflecting a blended 

reduction target for that state’s fossil 

fired EGUs, and provided that states 

could either meet that rate-based goal or 

convert it to a mass-based equivalent 

goal. Reflecting the final BSER 

described in section V and in response 

to many comments desirous that the 

EPA establish mass-based goals in the 

final rule, these final guidelines include 

three approaches that states may adopt 

for purposes of implementing the BSER, 

any one of which a state may use in its 

plan. These are: (1) Establishing 

standards of performance that apply the 

subcategory-specific CO2 emission 

performance rates to their affected 

EGUs, (2) adopting a combination of 

standards and/or other measures that 

achieve state-specific rate-based goals 

that represent the weighted aggregate of 

the CO2 emission performance rates 

applied to the affected EGUs in each 

state, and (3) adopting a program to 

meet mass-based CO2 emission goals 

that represent the equivalent of the ratebased goal for each state. These 

alternatives, as well as the other options 

we are finalizing, ensure that both states 

and affected EGUs enjoy the maximum 

flexibility and latitude in meeting the 

requirements of the emission guidelines 

and that the BSER is fully implemented 

by each state. 

In the proposal, we provided two 

designs for state plans: One where all 

the reduction obligations are placed 

directly on the affected EGUs and one, 

which we called the ‘‘portfolio 

approach,’’ that could include measures 

to be implemented, in whole or in part, 

by parties other than the affected EGUs. 

In the final guidelines, we retain that 


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768Rate-based and mass-based emission standards 

may incorporate the use of emission trading. 

basic choice, but with some 

modifications to respond to comments 

we received, especially on the portfolio 

approach. In their plans, states will be 

able to choose either to impose federally 

enforceable emission standards that 

fully meet the emission guidelines 

directly on affected EGUs (the 

‘‘emission standards’’ approach) or to 

use a ‘‘state measures’’ approach, which 

would be composed, at least in part, of 

measures implemented by the state that 

are not included as federally enforceable 

components of the plan but result in the 

affected EGUs meeting the requirements 

of the emission guidelines. A state 

measures type plan must include a 

backstop of federally enforceable 

standards on affected EGUs that fully 

meet the emission guidelines and that 

would be triggered if the state measures 

fail to result in the affected EGUs 

achieving on schedule the required 

emission reductions. 

States that choose an emission 

standards plan may establish as 

standards of performance for their 

affected EGUs the subcategory-specific 

CO2 emission performance rates, which 

express the BSER.768 This would satisfy 

the requirement described in section 

VIII.D.2.a.3 that a state demonstrate its 

plan would achieve the CO2 emission 

performance rates; in this case, no 

further demonstration would be 

necessary. Alternatively, a state may 

establish emission standards for affected 

EGUs at different levels from the 

uniform subcategory-specific emission 

performance rates, provided that when 

implemented, the emission standards 

achieve the CO2 emission performance 

rates or state rate- or mass-based CO2

emission goal set forth by the EPA for 

the state. States that adopt differential 

standards of performance among their 

affected EGUs must demonstrate that, in 

the aggregate, the differential standards 

of performance will result in their 

affected EGUs meeting the CO2 emission 

performance rates, the state’s rate-based 

CO2 emission goal or its mass-based CO2

emission goal. 

In the proposal, we proposed that 

states could use the portfolio approach 

to meet either a rate- or mass-based goal. 

In these final emission guidelines, the 

state measures approach is available 

only for a state choosing a mass-based 

CO2 emission goal, to provide certainty 

that the state measures are achieving the 

required emission reductions. Similar to 

emission standards plans with 

differential standards of performance, 

states that adopt state measures plans 

must demonstrate that the state 

measures, alone or in conjunction with 

any federally enforceable emission 

standards on affected EGUs also 

included in the state plan, will result in 

the affected EGUs in the state meeting 

the state’s mass-based CO2 emission 

goal. A ‘‘state measures’’ type plan must 

also include a backstop provision— 

triggered if, during the interim period, 

the state plan fails to achieve the 

emission reduction trajectory identified 

in the plan or if, during the final phase, 

the state plan fails to meet the final state 

mass-based CO2 emission goal—that 

would impose federally enforceable 

emission standards on the affected 

EGUs adequate to meet the emission 

guidelines when fully implemented. 

The final guidelines reflect the 

changes to the timing of the reductions 

within the interim period, which is laid 

out in section V as part of the 

determination of the BSER. States may 

adopt in their plans emission reduction 

trajectories different from the 

illustrative three-step trajectory 

included in these guidelines for 

purposes of creating a ‘‘glide path’’ 

between 2022 and 2029, provided that 

the interim and final CO2 emission 

performance rates or state CO2 emission 

goals are met. 

We recognize that while we are 

establishing 2022 as the date by which 

the period for mandatory reductions 

must start as part of our BSER 

determination, utilities and other parties 

are moving forward with projects that 

reduce emissions of CO2 from affected 

EGUs. We received numerous comments 

urging us to allow credit for these early 

actions. The final guidelines encourage 

those early reductions, by making clear 

that states may, in their plans, allow 

EGUs to use allowances or ERCs 

generated through the CEIP. The final 

guidelines also require that states 

include in their final plans a schedule 

of the actions they will be taking to 

ensure that the period for mandatory 

reductions will begin as required 

starting in 2022, and submit a progress 

report on those actions. 

For all types of plans, the final 

guidelines make clear that states may 

adopt programs that allow trading 

among affected EGUs. The final 

guidelines retain the flexibility for states 

to do individual plans, or to join with 

other states in a multi-state plan. In 

addition, and in response to comments 

from many states and other 

stakeholders, the guidelines provide 

that states may design their programs so 

that they are ‘‘ready for interstate 

trading,’’ that is, that they contain 

features necessary and suitable for their 

affected EGUs to engage in trading with 

affected EGUs in other ‘‘trading ready’’ 

states without the need for formal 

arrangements between individual states. 

We have been mindful of the concerns 

raised by stakeholders about reliability. 

The final BSER, especially the changes 

in the timing of the interim period, 

substantially address these concerns. 

The flexibilities provided for the design 

of state plans, including the ability to 

use trading programs, further enhance 

system reliability. We have included, as 

an additional assurance, a reliability 

safety valve for use where the built-in 

flexibilities are not sufficient to address 

an immediate, unexpected reliability 

situation. 

The EPA believes that all the 

flexibilities provided in the final rule 

are not only appropriate, but will 

enhance the success of the program. CO2

is a global pollutant, and where and 

when the reductions occur is not as 

significant to the environmental 

outcome as compared to many other 

pollutants. The flexibilities provided in 

the final guidelines will better reflect 

the unique interconnectedness of the 

electricity system, and will allow states 

and EGUs to reduce CO2 emissions 

while maintaining reliability and 

affordability for all consumers. 

In developing the plan, the state 

rulemaking process must meet the 

minimum public participation 

requirements of the implementing 

regulations as applicable to these 

guidelines, including a public hearing 

and meaningful engagement with all 

members of the public, including 

vulnerable communities. In the 

community and environmental justice 

considerations section, section IX of this 

preamble, the EPA addresses the actions 

that the agency is taking to help ensure 

that vulnerable communities are not 

disproportionately impacted by this 

rule. These actions include conducting 

a proximity analysis, setting 

expectations for states to engage 

meaningfully with vulnerable 

communities and requiring that they 

describe their plans for doing so as they 

develop their state plans, providing 

communities with access to additional 

resources, providing communities with 

information on federal programs and 

resources available to them, 

recommending that states take a multipollutant planning approach that 

examines the potential impacts of copollutants on overburdened 

communities, and conducting an 

assessment to determine if any localized 

air quality impacts need to be further 

addressed. Additionally, the EPA 

outlines the continued engagement that 

it will be conducting with states and 

communities throughout the state plan 

development process. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64828 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

769A federal plan may be withdrawn if the state 

submits, and the EPA approves, a state plan that 

meets the requirements of this final rule and section 

111(d) of the CAA. More details regarding the 

federal plan are addressed in the EPA’s proposed 

federal plan rulemaking. 

770States are free to establish different interim 

step performance rates or interim step state goals 

than those the EPA has specified in this final rule. 

If states choose to determine their own interim step 

performance rates or state goals, the state must 

demonstrate that the plan will still meet the interim 

performance rates or state goal for 2022–2029 

finalized in this action. 

As discussed in more detail in section 

VIII.E, commenters, particularly states, 

provided compelling information 

establishing that for some, and perhaps 

many, states it will take longer than the 

agency initially anticipated to develop 

and submit their required plans. In 

response to those comments, we are 

finalizing a plan submittal process that 

provides additional time for states that 

need it to submit a final plan submittal 

to the EPA after September 6, 2016. 

Within the time period specified in the 

emission guidelines (from as early as 

September 6, 2016, to as late as 

September 6, 2018, depending on 

whether the state receives an extension), 

the state must submit its final state plan 

to the EPA. The EPA then must 

determine whether to approve or 

disapprove the plan. If a state does not 

submit a plan, or if the EPA disapproves 

a state’s plan, then the EPA has the 

express authority under CAA section 

111(d) to establish a federal plan for the 

state.769 During and following 

implementation of its approved state 

plan, each state must demonstrate to the 

EPA that its affected EGUs are meeting 

the interim and final performance 

requirements included in this final rule 

through monitoring and reporting 

requirements. 

This section is organized as follows. 

First, we discuss the timeline for state 

plan performance and provisions to 

encourage early action. Second, we 

describe the types of plans that states 

can submit. Third, we summarize the 

components of an approvable state plan 

submittal. Fourth, we address the 

process and timing for submittal of state 

plans and plan revisions. Fifth, we 

address plan implementation and 

achievement of CO2 emission 

performance rates or state CO2 emission 

goals for affected EGUs, and the 

consequences if they are not met. Sixth, 

we discuss general considerations for 

states in developing and implementing 

plans, including consideration of a 

facility’s ‘‘remaining useful life’’ and 

‘‘other factors’’ and electric reliability. 

Seventh, we note certain resources that 

are available to facilitate state plan 

development and implementation. 

Finally, we discuss additional 

considerations for inclusion of CO2

emission reduction measures in state 

plans, including: Accounting for 

emission reduction measures in state 

plans; requirements for mass-based and 

rate-based emission trading approaches; 

EM&V requirements for RE and 

demand-side EE resources and other 

measures used to adjust a CO2 rate; and 

treatment of interstate effects. 

B. Timeline for State Plan Performance 

and Provisions To Encourage Early 

Action 

This section describes state plan 

requirements related to the timing of 

achieving the emission reductions 

required in the guidelines and the state 

plan performance periods. This section 

also describes the CEIP the EPA is 

establishing to encourage early 

investment in certain types of RE 

projects, as well as in demand-side EE 

projects implemented in low-income 

communities. 

1. Timeline for State Plan Performance 

The final guidelines establish three 

types of performance periods: (1) A final 

deadline by which and after which 

affected EGUs must be in compliance 

with the final reduction requirements, 

(2) an interim period, and (3) within 

that interim period, three multi-year 

interim step periods. As discussed 

below and in section V, these 

performance periods are consistent with 

our determination of the BSER and are 

also responsive to the key comments we 

received on this aspect of the state 

plans. 

A performance period is a period for 

which the final plan submittal must 

demonstrate that the required CO2

emission performance rates or state CO2

emission goal will be met. The final 

guidelines establish 2030 as the 

deadline for compliance by affected 

EGUs with the final CO2 emission 

performance rates or CO2 rate or mass 

emission goal; 2030 is the beginning of 

the final performance period. The 

interim performance period is 2022 to 

2029, and there are three interim step 

periods—2022–2024, 2025–2027, and 

2028–2029—where increasingly 

stringent emission performance rates or 

state emission goals must be met. The 

state may submit a plan that 

incorporates alternative interim step 

emission performance rates or state 

emission goals to those provided by 

EPA, as long as on average or 

cumulatively, as appropriate, they result 

in the equivalent of the interim 

emission performance rates or state 

emission goals in the emission 

guidelines. These timelines are based on 

careful consideration of the substantial 

comments we received on both the 

timing of the interim period and the 

trajectory of compliance by affected 

EGUs over the interim period and our 

determination of the BSER, discussed in 

section V above. The modifications we 

have made to the timelines included in 

the proposal respond to these comments 

and to concerns about, among other 

things, reliability, feasibility, and cost. 

As previously discussed, the EPA has 

determined that the BSER includes 

implementation of reduction measures 

over the period of 2022 through 2029, 

with final compliance by affected EGUs 

in 2030. Therefore, the final rule 

requires that interim CO2 emission 

performance rates or state CO2 emission 

goals be met for the interim period of 

2022–2029. Many commenters 

expressed a desire that the EPA 

designate steps during the interim 

period to create an interim goal that 

offered states and utilities greater 

flexibility and choice in determining 

their own emission reduction 

trajectories over the course of the 

interim period. Since our intent at 

proposal was to provide such flexibility 

and choice, and since it remains our 

intent to do so in this final rule, we are 

addressing these comments by 

including in the 2022–2029 interim 

period three interim step periods (2022– 

2024, 2025–2027, 2028–2029), which 

correspond roughly to the phasing in of 

the BSER. We note, however, that the 

final rule also allows states the 

flexibility to define an alternate 

trajectory of emission performance 

between 2022 and 2029, provided that 

(1) the state plan specifies its own 

interim step CO2 emission performance 

rates or state CO2 emission goals, (2) 

meeting the alternative interim step CO2

emission performance rates or state CO2

emission goals will result in the interim 

emission performance rates or state CO2

emission goal being met on an 8-year 

average or cumulative basis, and, (3) the 

final CO2 emission performance rates or 

state CO2 emission goal is achieved. To 

be approvable, a state plan submittal 

must demonstrate that the emission 

performance of affected EGUs will meet 

the interim step CO2 emission 

performance rates or interim step state 

CO2 emission goals over the 2022–2024, 

2025–2027, and 2028–2029 periods and 

the final CO2 emission performance 

rates or state CO2 emission goal no later 

than 2030.770

This relatively long period—first for 

planning, then for implementation and 

achievement of the interim and final 

CO2 emission performance rates or state 

CO2 emission goals—provides states and 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64829 

771Modifications to state plans are addressed 

more specifically in section VIII.E.7 below. 

utilities with substantial flexibility 

regarding methods and timing of 

achieving emission reductions from 

affected EGUs. The EPA believes that 

timing flexibility in implementing 

measures provides significant benefits 

that allow states to develop plans that 

will help achieve a number of goals, 

including, but not limited to: Reducing 

cost, addressing reliability concerns, 

addressing concerns about stranded 

assets, and facilitating the integration of 

meeting the emission guidelines and 

compliance by affected EGUs with other 

air quality and pollution control 

obligations on the part of both states and 

affected EGUs. Moreover, we note that 

over the course of time between 

submittal of final plans and 2030, 

circumstances may change such that 

states may need or wish to modify their 

plans. The relatively lengthy 

performance periods provided in the 

final rule should help keep those 

situations to a minimum but will also 

accommodate them if necessary.771 The 

EPA envisions that the agency, states 

and affected EGUs will have an ongoing 

relationship in the course of 

implementing this program. Since the 

record also indicates a high degree of 

interest on the part of states and 

stakeholders in pursuing banking and 

trading programs, the timing and level 

of stringency of the interim CO2

performance rates or state CO2 emission 

goals we are finalizing should provide 

states and affected EGUs with ample 

capacity to accommodate such changes 

without necessitating changes in state 

plans in many instances. 

The timelines established in the final 

rule respond to the issues raised in 

numerous comments regarding the 

concept of the interim period, including 

comments supporting the flexibility 

afforded states in developing their plans 

and the timing necessary to meet the 

2030 emission requirements. Some 

commenters supported beginning the 

interim goal plan period at 2020. Others 

stated that the investments necessary to 

meet the proposed interim emission 

performance goals beginning in 2020 are 

unachievable in that timeframe or 

would place too great a burden on 

affected EGUs, states, and ratepayers. 

Some suggested that the 2020 interim 

goal step should be eliminated in favor 

of later start dates, including 2022, 

2025, or other years. Some commenters 

urged the EPA to establish phased 

interim steps creating a steady 

downward trajectory that allowed 

several years for each step, compatible 

with the ‘‘chunkiness’’ of utility 

planning processes. Yet other 

commenters provided input suggesting 

that states be allowed to establish their 

own set of emission performance steps 

during the interim plan performance 

period and thereby control their own 

emission reduction trajectory or ‘‘glide 

path’’ for achievement of the interim 

goal and the 2030 goal, or that the EPA 

not establish any interim standards at 

all. Commenters also noted that for 

some states, there was not a significant 

difference between the interim and final 

goal, and, therefore, no glide path for 

those states. As discussed in previous 

sections, based on this input and our 

final determination of the BSER, the 

EPA has adjusted the interim period to 

include 2022–2029, is establishing three 

interim performance periods creating a 

reasonable trajectory from 2022 to 2030, 

and is also retaining the flexibility for 

states to establish their own emission 

reduction trajectory during the interim 

period. 

As noted, the EPA has determined 

that the period for mandated reductions 

should begin in 2022, instead of 2020 as 

we proposed, because of the substantial 

amount of comment and data we 

received indicating that states and 

utilities reasonably needed that 

additional time to take the steps 

necessary to start achieving reductions. 

In order to assure the EPA and the 

public that states are making progress in 

implementing the plan between the time 

of the state plan submittal and the 

beginning of the interim period, and as 

discussed in further detail in section 

VIII.D, the final rule requires that the 

state plan submittal include a timeline 

with all the programmatic plan 

milestone steps the state will take 

between the time of the state plan 

submittal and 2022 to ensure the plan 

is effective as of 2022. 

2. Provisions To Encourage Early Action 

Many commenters supported 

providing incentives for states and 

utilities to deploy CO2-reducing 

investments, such as RE and demandside EE measures, as early as possible. 

In the proposal, the EPA requested 

comment on an approach that would 

recognize emission reductions that 

existing programs provide prior to the 

initial plan performance period starting 

from a specified date. We also requested 

comment on options for that specified 

date and on conditions that should 

apply to counting those pre-compliance 

emission reductions toward a state goal. 

The EPA received many comments 

requesting that the agency recognize 

early actions for the emission reductions 

they provide prior to the performance 

period, that the EPA allow those precompliance impacts to be counted 

toward meeting requirements under the 

rule, and that certain conditions should 

be applied to recognition of early 

reductions so as to ensure the emission 

reductions required in the rule. We also 

received comments from stakeholders 

regarding the disproportionate burdens 

that some communities already bear, 

and stating that all communities should 

have equal access to the benefits of 

clean and affordable energy. The EPA 

recognizes the validity and importance 

of these perspectives, and as a result has 

determined to provide a program— 

called the Clean Energy Incentive 

Program (CEIP)—in which states may 

choose to participate. This section 

describes this program. 

The CEIP is designed to incentivize 

investment in certain RE and demandside EE projects that commence 

construction in the case of RE, or 

commence operation in the case of EE, 

following the submission of a final state 

plan to the EPA, or after September 6, 

2018, for states that choose not to 

submit a final state plan by that date, 

and that generate MWh (RE) or reduce 

end-use energy demand (EE) during 

2020 and/or 2021. State participation in 

the program is optional; the EPA is 

establishing this program as an 

additional flexibility to facilitate 

achievement of the CO2 emission 

reductions required by this final rule, 

regardless of the type of state plan a 

state chooses to implement. 

Under the CEIP, a state may set aside 

allowances from the CO2 emission 

budget it establishes for the interim plan 

performance period or may generate 

early action ERCs (ERCs are discussed 

in more detail in section VIII.K.2), and 

allocate these allowances or ERCs to 

eligible projects for the MWh those 

projects generate or the end-use energy 

savings they achieve in 2020 and/or 

2021. A state implementing a massbased plan approach, as described in 

section VIII.C, may issue early action 

allowances; a state implementing a ratebased plan approach, also described in 

section VIII.C, may issue early action 

ERCs. For each early action allowance 

or ERC a state allocates to such projects, 

the EPA will provide the state with an 

appropriate number of matching 

allowances or ERCs, as outlined below, 

for the state to allocate to the project. 

The EPA will match state-issued early 

action ERCs and allowances up to an 

amount that represents the equivalent of 

300 million short tons of CO2 emissions. 

The EPA intends that a portion of this 

pool will be reserved for eligible wind 

and solar projects, and a portion will be 

reserved for low-income EE projects. In 

the proposed federal plan, the EPA is 


tkelley on DSK3SPTVN1PROD with BOOK 2
64830 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

772U.S. Energy Information Administration 

Electric Power Annual 2013. http://www.eia.gov/

electricity/annual. Table 4.6: Capacity additions, 

retirements and changes by energy source. March 

2015. 

773U.S. Energy Information Administration 

Electric Power Monthly. http://www.eia.gov/

electricity/monthly. Table 6.3: New Utility Scale 

Generating Units by Operating Company, Plant, 

Month, and Year. 

774 GTM Research/Solar Energy Industries 

Association: U.S. Solar Market Insight Q1 2015. 

775This may occur because not all states may 

elect to include requirements for CEIP participation 

in their state plans. 

taking comment on the size of each 

reserve, and is proposing provisions to 

provide that any unallocated amounts 

would be redistributed among 

participating states. 

The EPA has determined that the size 

of this 300 million short ton CO2- 

equivalent matching pool is an 

appropriate reflection of the CO2

emission reductions that could be 

achieved by the additional early 

investment in RE and demand-side EE 

the agency expects will be incentivized 

by the CEIP. For example, in 2012, 13 

GW of utility scale wind were 

deployed,772 and, in 2014, 3.4 GW of 

utility-scale solar 773 plus 2–3 GW of 

distributed solar were deployed,774

according to industry estimates. 

Assuming 19 GW per year of RE from 

2017–2020 based on these historic 

maximums yields an installed base of 76 

GW of RE potentially eligible for CEIP 

incentives in 2020 and/or 2021. 

Assuming an average capacity factor of 

30 percent, this would translate into 

approximately 200 TWh/year of 

generation, which would be eligible for 

approximately 300 million short tons of 

matching allowances over the 2-year 

period, if the RE MWh were converted 

to allowances based on the 2012 carbon 

intensity of 0.8 short tons per MWh. 

This would leave the remaining half of 

the pool of matching federal allowances 

available for EE projects implemented in 

low-income communities, and 

additional growth in RE deployment 

beyond these historic maximums as 

potentially enabled by reductions in 

cost and improvements in performance. 

For a state to be eligible for a 

matching award of allowances or ERCs 

from the EPA, it must demonstrate that 

it will award allowances or ERCs only 

to eligible projects. These are projects 

that: 

• Are located in or benefit a state that 

has submitted a final state plan that 

includes requirements establishing its 

participation in the CEIP; 

• Are implemented following the 

submission of a final state plan to the 

EPA, or after September 6, 2018, for a 

state that chooses not to submit a 

complete state plan by that date; 

• For RE: Generate metered MWh 

from any type of wind or solar 

resources; 

• For EE: Result in quantified and 

verified electricity savings (MWh) 

through demand-side EE implemented 

in low-income communities; and 

• Generate or save MWh in 2020 and/ 

or 2021. 

The following provisions outline how 

a state may award early action ERCs or 

allowances to eligible projects, and how 

the EPA will provide matching ERCs or 

allowances to states. 

• For RE projects that generate 

metered MWh from any type of wind or 

solar resources: For every two MWh 

generated, the project will receive one 

early action ERC (or the equivalent 

number of allowances) from the state, 

and the EPA will provide one matching 

ERC (or the equivalent number of 

allowances) to the state to award to the 

project. 

• For EE projects implemented in 

low-income communities: For every two 

MWh in end-use demand savings 

achieved, the project will receive two 

early action ERCs (or the equivalent 

number of allowances) from the state, 

and the EPA will provide two matching 

ERCs (or the equivalent number of 

allowances) to the state to award to the 

project. 

Early action allowances or ERCs 

awarded by the state, and matching 

allowances or ERCs awarded by the EPA 

pursuant to the CEIP, may be used for 

compliance by an affected EGU with its 

emission standards and are fully 

transferrable prior to such use. 

The EPA discusses the CEIP in the 

proposed federal plan rule, and will 

address design and implementation 

details of the CEIP, including the 

appropriate factor for determining 

equivalence between allowances and 

MWh and the definition of a lowincome community for project eligibility 

purposes, in a subsequent action. Before 

doing so, the EPA will engage states and 

stakeholders to gather additional 

information concerning implementation 

topics, and to solicit information about 

the concerns, interests and priorities of 

states, stakeholders and the public. 

In order for a state that chooses to 

participate in the CEIP to be eligible for 

a future award of allowances or ERCs 

from the EPA, a state must include in its 

initial submittal a non-binding 

statement of intent to participate in the 

program. In the case of a state 

submitting a final plan by September 6, 

2016, the state plan would either 

include requirements establishing the 

necessary infrastructure to implement 

such a program and authorizing its 

affected EGUs to use early action 

allowances or ERCs as appropriate, or 

would include a non-binding statement 

of intent as part of its supporting 

documentation and revise its plan to 

include those requirements at a later 

date. 

Following approval of a final state 

plan that includes requirements for 

implementing the CEIP, the agency will 

create an account of matching 

allowances or ERCs for the state that 

reflects the pro rata share—based on the 

amount of the reductions from 2012 

levels the affected EGUs in the state are 

required to achieve relative to those in 

the other participating states—of the 300 

million short ton CO2 emissionsequivalent matching pool that the state 

is eligible to receive. Thus, states whose 

EGUs have greater reduction obligations 

will be eligible to secure a larger 

proportion of the federal matching pool 

upon demonstration of quantified and 

verified MWh of RE generation or 

demand side-EE savings from eligible 

projects realized in 2020 and/or 2021. 

Any matching allowances or ERCs 

that remain undistributed after 

September 6, 2018,775 will be 

distributed to those states with 

approved state plans that include 

requirements for CEIP participation. 

These ERCs and allowances will be 

distributed according to the pro rata 

method outlined above. Unused 

matching allowances or ERCs that 

remain in the accounts of states 

participating in the CEIP on January 1, 

2023, will be retired by the EPA. 

For purposes of establishing a state 

plan program eligible for an award of 

matching allowances or ERCs from the 

EPA, such a program must include a 

mechanism for awarding early action 

emission allowances or ERCs for eligible 

actions that reduce or avoid CO2

emissions in 2020 and/or 2021, and that 

is implemented in a way such that the 

early action allowances or ERCs 

allocated by the state would maintain 

the stringency of the state’s goal for 

emission performance from affected 

EGUs in the performance periods 

established in this rule. Specifically, the 

state must demonstrate in its plan that 

it has a mechanism in place that enables 

issuance of ERCs or allowances from the 

state to parties effectuating reductions 

in 2020 and/or 2021 in a manner that 

would have no impact on the aggregate 

emission performance of affected EGUs 

required to meet rate-based or massbased CO2 emission standards during 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64831 

776For example, under a mass-based 

implementation, the state plan could include a setaside of early action allowances from an emissions 

budget that itself reflects the state goals. Allocation 

of those early action allowances to parties 

effectuating reductions in 2020 and 2021 would 

have no impact on the total emissions budget, 

which sets the total allowable emissions in the 

compliance periods. Alternatively, under a ratebased implementation, the state plan could require 

that early action ERCs issued to parties effectuating 

reductions in 2020 and 2021 would be ‘‘borrowed’’ 

from a pool of ERCs created by the state during the 

interim plan performance period. States could limit 

the size of the ‘‘borrowed’’ pool of ERCs to be 

equivalent to the size of the federal matching pool, 

or could take into consideration the potential for 

each state’s federal matching pool to expand after 

a redistribution of unused credits. For every early 

action ERC awarded for actions in 2020 and 2021, 

the state would retire one ERC from the pool of 

ERCs created as a result of reductions achieved 

from 2022 onward. 

777 In addition to the CEIP, states may also offer 

credit for early investments in RE and demand-side 

EE according to the provisions of section VIII.K.1 

of this final rule: A state may award ERCs to 

qualified providers that implement projects from 

2013 onward that realize quantified and verified 

MWh results in 2022 and subsequent years. 

778Several of these programs are discussed in 

section IX of this preamble, including, for example, 

Maryland’s EmPOWER Low Income Energy 

Efficiency Program (LIEEP) and New York’s 

EmPower New York program. 

the compliance periods.776 This 

demonstration is not required to 

account for matching ERCs or 

allowances that may be issued to the 

state by the EPA. Participation in this 

program is entirely voluntary, and 

nothing in these provisions would have 

the effect of requiring any particular 

affected EGU to achieve reductions prior 

to 2022, or requiring states to offer 

incentives for emission reductions 

achieved prior to 2022.777 These and 

other details will be developed in the 

subsequent action. 

The EPA is providing the CEIP as an 

option for states implementing plans— 

and is including a similar program for 

the federal plan proposal being issued 

concurrently—for several reasons. Chief 

among them is that offered by 

commenters to the effect that the overall 

cost of achievement of the emission 

performance rates or state goals could be 

reduced by an approach that granted 

some form of beneficial recognition to 

emissions reduction investments that 

both occur and yield reductions prior to 

the first date on which the program of 

the interim plan performance period. 

Other commenters pointed out that to 

the extent that states and utilities would 

benefit from the availability of low-cost 

RE and other zero-emitting generation 

options during the interim and final 

plan performance periods, the EPA 

should include in the final emission 

guidelines provisions that accelerate 

deployment of RE resources, since in so 

doing the final emission guidelines 

would speed achievement of expected 

reductions in the cost of those 

technologies commensurate with their 

accelerated deployment. In addition, the 

incentives and market signal generated 

by the CEIP can help sustain the 

momentum toward greater RE 

investment in the period between now 

and 2022 so as to offset any dampening 

effects that might be created by setting 

the start date 2 years later than at 

proposal. 

The specific criteria the EPA is 

establishing for eligible RE projects 

reflect a variety of considerations. First, 

the EPA seeks to preserve the incentive 

for project developers to execute on 

planned investments in all types of solar 

and wind technologies. Commenters 

raised concerns that the fast pace of 

reductions underlying the emission 

targets in the proposed rule could 

potentially shift investment from RE to 

natural gas, thus dampening the 

incentive to develop wind and solar 

projects, in particular. Second, the EPA, 

consistent with the CAA’s design that 

incentivizes technology and accelerates 

the decline in the costs of technology, 

seeks to drive the widespread 

development and deployment of wind 

and solar, as these broad categories of 

renewable technology are essential to 

longer term climate strategies. Finally, 

in contrast to other CO2-reducing 

technologies—including other zeroemitting or RE technologies—solar and 

wind projects often require lead times of 

shorter duration, which would allow 

them to generate MWh beginning in 

2020. 

The specific criterion the EPA is 

establishing for eligible EE projects— 

namely that these projects be 

implemented in low-income 

communities—is also consistent with 

the technology-forcing and development 

design of CAA section 111. The EPA 

believes it is appropriate to offer an 

additional incentive to remove current 

barriers to implementing demand-side 

EE programs in low-income 

communities. While the EPA 

acknowledges that a number of states 

have demand-side EE programs focused 

on these communities,778 the agency 

also recognizes that there have been 

historic economic, logistical, and 

information barriers to implementing 

programs in these communities. As a 

result, the costs of implementing 

demand-side EE programs in these 

communities are typically higher than 

in other communities and stand as 

barrier to harvesting potentially cost 

effective reductions and advancing 

these technologies. The EPA intends for 

the CEIP to help incentivize increased 

deployment of projects that will deliver 

demand-side EE benefits to these 

communities, which will in turn lower 

the costs of these approaches. These 

lower costs will help new technologies 

and delivery mechanisms penetrate in 

the future, thus improving the cost of 

implementation of the emission 

guidelines overall, consistent with 

Congress’ design in the New Source 

Performance Standard provisions of the 

CAA. Further, reducing barriers to 

demand-side EE in low-income 

communities will help ensure that the 

benefits of the final rule are shared 

broadly across society and that potential 

adverse impacts on low-income 

ratepayers are avoided. It complements 

other steps the federal government is 

taking to bring clean energy 

technologies to these communities, as 

we discuss in section IX of this 

preamble. 

More broadly, the CEIP responds to 

the urgency of meeting the challenge of 

climate change in two key ways. First, 

of course, it fosters reductions before 

2022. Second, in targeting investments 

in wind, solar and low-income EE, it 

focuses on the kinds of measures and 

technologies that are the essential 

foundation of longer-term climate 

strategies, strategies that inevitably 

depend on the further development and 

widespread deployment of highly 

adaptable zero-emitting technologies. 

We are not requiring that projects 

demonstrate to states that they are 

‘‘additional’’ or surplus relative to a 

business-as-usual or state goal-related 

baseline in order to be eligible. At the 

same time, we believe that including an 

incentive to develop projects that 

benefit low-income communities will 

increase the likelihood of investments 

being made that would not have been 

made otherwise. 

In order to be awarded matching ERCs 

or allowances by the EPA for projects 

that meet the eligibility criteria, a final 

state plan must have requirements 

establishing the appropriate 

infrastructure to issue early action ERCs 

or allowances to eligible project 

providers by 2020. The state must 

require that the state or its agent will, in 

accordance with state plan requirements 

approved as meeting the ERC issuance 

and EM&V requirements included in 

section VIII.K: (1) Evaluate project 

proposals from eligible RE and demandside EE project providers, including the 

EM&V plans that must accompany such 

proposals; (2) evaluate monitoring and 

verification reports submitted by 

eligible providers following project 

implementation, which contain the 

quantified and verified MWh of RE 

generation or energy savings achieved 


tkelley on DSK3SPTVN1PROD with BOOK 2
64832 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

779For a state plan incorporating the use of ERCs 

or allowances to be approvable by the EPA, such 

a plan must use an EPA-approved or EPAadministered tracking system for ERCs or 

allowances. The EPA received a number of 

comments from states and stakeholders about the 

value of the EPA’s support in developing and/or 

administering tracking systems to support state 

administration of rate-based emission trading 

programs. The EPA is exploring options for 

providing such support and is conducting an initial 

scoping assessment of tracking system support 

needs and functionality. 

780The CEIP is expected to provide states and 

affected EGUs additional flexibility in meeting the 

guidelines, and bears similarity in both design and 

purpose to the Compliance Supplement Pool, 

which the agency established as a part of the NOX

SIP Call. See 63 FR 57356, 57428–30 (Oct. 27, 

1998). Certain aspects of the Compliance 

Supplement Pool were challenged in litigation and 

upheld by the D.C. Circuit Court of Appeals. See 

Michigan v. EPA, 213 F.3d 663, 694 (D.C. Cir. 2000). 

781 40 CFR 60.21(f) defines ‘‘emission standard’’ 

as ‘‘a legally enforceable regulation setting forth an 

allowable rate of emissions into the atmosphere, 

establishing an allowance system, or prescribing 

equipment specifications for control of air pollution 

emissions.’’ This definition is promulgated and 

effective, and we note that it authorizes the use of 

allowance systems as a form of emission standard. 

To resolve any doubt that allowance systems are an 

acceptable form of emission standard in the final 

rule, we are including regulatory text in the final 

subpart UUUU regulations authorizing the use of 

allowance systems as a form of emission standard 

under section 111(d). Section 60.21(f) was 

originally amended in 2005 to include recognition 

of allowance systems as a form of emission standard 

in the Clean Air Mercury Rule (CAMR) (70 FR 

28606, 28649; May 18, 2005). CAMR was vacated 

in its entirety in New Jersey v. EPA, 517 F.3d 574 

(D.C. Cir. 2008). However, the reason for vacatur 

was wholly unrelated to the question of whether an 

allowance system could be a form of emission 

standard. In response to the New Jersey decision, 

the agency removed CAMR provisions from the 

Code of Federal Regulations. The agency chose to 

retain the language of 60.21(f) and 60.24(b)(1) 

generally recognizing allowance systems. This 

language is broader than CAMR and unrelated to 

the reasons for its vacatur. The EPA re-promulgated 

these provisions in February of 2012 (77 FR 9304, 

9447; Feb. 16, 2012). Even if this were not the case, 

the agency would not concede that simply because 

‘‘allowance systems’’ were not provided for in the 

framework regulations of subpart B, they could not 

be relied upon in specific emission guidelines, such 

as these for CO2. The implementing regulations 

generally serve a gap-filling role where there are not 

more specific provisions laid out in the relevant 

emission guidelines. In order to resolve any 

question whether allowance systems are authorized 

under the final rule, we are including regulatory 

text in subpart UUUU to make this authorization 

explicit. 

782 ‘‘State measures’’ refer to measures that are 

adopted, implemented, and enforced 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. 

783New source CO2 emission complements are 

discussed in section VIII.J.2.b, which also provides 

EPA-derived new source CO2 emission 

complements for states. 

by the project in 2020 and/or 2021; (3) 

issue ERCs or allowances to eligible 

providers for these MWh results; (4) 

ensure that no MWh of renewable 

generation or energy savings receives 

early action or matching ERCs or 

allowances more than once.779

The CEIP will provide a number of 

benefits. First, the program will provide 

incentives designed to reduce energy 

bills early in the implementation of the 

guidelines through earlier and broader 

application of energy saving 

technologies, and help ensure that these 

benefits are fully shared by low-income 

communities. Second, the EPA believes 

that stimulating or supporting early 

investment in RE generation 

technologies could accelerate the rate at 

which the costs of these technologies 

fall over the course of the interim 

performance period. Third, the CEIP 

will provide affected EGUs and states 

with additional emission reduction 

resources to help them achieve their 

state plan obligations. Finally, the 

program will improve the liquidity, in 

the early years of the program, of the 

ERC and allowance markets we expect 

to emerge for compliance with the 

requirements of these guidelines.780

The EPA is establishing this program 

as an option for states that wish to drive 

investments in RE and low-income EE 

that will result in actual, early 

reductions in CO2 emissions from 

affected EGUs. States are also 

authorized to set their own glide path, 

or interim step performance rates or 

goals, so long as the interim and final 

performance rates or goals are met, and 

could do so in a way that takes into 

account the availability of the CEIP to 

assist affected EGUs in meeting the 

applicable glide path and performance 

rates or goals. While the EPA is not 

requiring states to take advantage of this 

program, its availability simply 

enhances these already-existing 

implementation and compliance 

flexibilities while at the same time 

delivering meaningful benefits, 

particularly for low-income 

communities. The EPA looks forward to 

an upcoming public dialogue about the 

implementation details of the CEIP. 

C. State Plan Approaches 

1. Overview 

Under the final emission guidelines, 

states may adopt and submit either of 

two different types of state plans. The 

first would apply all requirements for 

meeting the emission guidelines to 

affected EGUs in the form of federally 

enforceable emission standards.781 We 

refer to this as an ‘‘emission standards’’ 

state 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 measures 782 that apply to 

affected EGUs, other entities, or some 

combination thereof. The state measures 

plan type also includes a mandatory 

contingent backstop of federally 

enforceable emission standards for 

affected EGUs that would apply in the 

event the plan does not achieve its 

anticipated level of emission 

performance as specified in the state 

plan during the period that the state is 

relying on state measures. The inclusion 

of a backstop of federally enforceable 

emission standards in a state measures 

plan type is legally necessary for a state 

plan to meet the terms of 111(d), which 

specifically require a state to submit 

standards of performance. 

These two types of state plans and 

their respective approaches, either of 

which could be implemented on a 

single-state or multi-state basis, allow 

states to meet the statutory requirements 

of CAA section 111(d) while 

accommodating the wide range of 

regulatory requirements and other 

programs that states have deployed or 

will deploy in the electricity sector that 

reduce CO2 emissions from affected 

EGUs. Further, as described in detail 

below, both types of plans are 

responsive to comments we received 

from states and other stakeholders. In 

addition to providing states the option 

of developing an emission standards or 

state measures type plan, the final rule 

makes clear that states that choose an 

emission standards plan can adopt a 

plan that meets either the CO2 emission 

performance rates, a rate-based CO2

emission goal, or a mass-based CO2

emission goal. 

Under these two basic plan types, the 

final emission guidelines provide states 

with a number of potential plan 

pathways for meeting the emission 

guidelines. A plan pathway represents a 

specific plan design approach used to 

meet the emission guidelines. These 

plan pathways are discussed in section 

VIII.C.2 through C.5 below, and further 

elaborated in sections VIII.J (for massbased emission standards) and VIII.K 

(for rate-based emission standards). 

The final emission guidelines provide 

four streamlined plan pathways. These 

streamlined plan pathways represent 

straightforward plan approaches for 

meeting the emission guidelines, and 

avoid the need to meet additional plan 

requirements and include additional 

elements in a plan submittal. The 

streamlined plan pathways include the 

following: 

• Establishing federally enforceable, massbased CO2 emission standards for affected 

EGUs, complemented by state-enforceable 

mass-based CO2 emission standards for new 

fossil fuel-fired EGUs.783 This approach 

could involve an emission budget trading 

program that includes affected EGUs as well 


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784Mass-based trading-ready plans are addressed 

in section VIII.J.3. Multi-state plans, where a group 

of states are meeting a joint CO2 goal for affected 

EGUs, are addressed in section VIII.C.5. 

785This plan approach would meet a state massbased CO2 goal for affected EGUs, or a joint multistate mass-based CO2 goal for affected EGUs. These 

plan approaches are discussed in sections VIII.J.2 

and VIII.C.5, respectively. 

786Submission of a state plan based on the EPA’s 

finalized model rule for a mass-based emission 

trading program could be considered presumptively 

approvable. The EPA would evaluate the 

approvability of such submission through an 

independent notice and comment rulemaking. 

787Rate-based trading-ready plans are addressed 

in section VIII.K.4. 

788This plan approach is addressed in section 

VIII.C.2.a. 

789This multi-state plan approach is addressed in 

section VIII.C.5. 

790The legal basis for authorizing trading in 

emission standards is discussed in section VIII.C.6. 

791The weighted average CO2 emission rate that 

will be achieved by the fleet of affected EGUs in a 

Continued 

as new fossil fuel-fired EGUs. This approach 

facilitates interstate emission trading, 

through either a single-state ‘‘ready-forinterstate-trading’’ plan approach or through 

a multi-state plan. Under a ‘‘ready-forinterstate-trading’’ plan, interstate emission 

trading may occur without the need for a 

multi-state plan.784

• Establishing federally enforceable, massbased CO2 emission standards for affected 

EGUs.785 This approach facilitates interstate 

emission trading, through either a single-state 

‘‘ready-for-interstate-trading’’ plan approach 

or through a multi-state plan. In a separate 

concurrent action, the EPA is proposing a 

model rule for states that could be used in 

a plan implementing this approach.786

• Establishing federally enforceable, 

subcategory-specific rate-based CO2 emission 

standards for affected EGUs, consistent with 

the CO2 emission performance rates in the 

emission guidelines. This approach provides 

for interstate emission trading, through either 

a single-state ‘‘ready-for-interstate-trading’’ 

plan approach or through a multi-state 

plan.787 In a separate concurrent action, the 

EPA is proposing a model rule for states that 

could be used in a plan implementing this 

approach. 

• Establishing federally enforceable ratebased CO2 emission standards at a single 

level that applies for all affected EGUs, 

consistent with the state rate-based CO2 goal 

for affected EGUs in the emission 

guidelines.788 This approach provides for 

interstate emission trading, through a multistate plan that meets a single weighted 

average multi-state rate-based CO2 goal.789

The final emission guidelines also 

provide for a range of additional custom 

plan approaches that a state may 

pursue, if it chooses, to address specific 

circumstances or policy objectives in a 

state. The custom plan pathways, while 

viable options for meeting the emission 

guidelines, come with additional plan 

requirements and plan submittal 

elements. These additional plan 

requirements and plan submittal 

elements are necessary to ensure that 

the emission guidelines are met and that 

the necessary level of CO2 emission 

performance is achieved by affected 

EGUs. 

Based on this overall approach, the 

final emission guidelines provide for a 

range of state options—both easily 

implementable approaches that can be 

used to meet the emission guidelines, 

and more customizable approaches that 

can be used, if a state chooses, to 

address special circumstances or state 

policy objectives. 

2. ‘‘Emission Standards’’ State Plan 

Type 

The emission standards type of state 

plan imposes requirements solely on 

affected EGUs in the form of federally 

enforceable emission standards. This 

type of state plan, as described below, 

may consist of rate-based emission 

standards for affected EGUs or massbased emission standards for affected 

EGUs. 

The state plan submittal for an 

emission standards type plan must 

demonstrate that these federally 

enforceable emission standards for 

affected EGUs will achieve the CO2

emission performance rates or the 

applicable state rate-based or massbased CO2 emission goal for affected 

EGUs. 

Both rate-based and mass-based 

emission standards included in a state 

plan must be quantifiable, verifiable, 

enforceable, non-duplicative and 

permanent. These requirements are 

described in more detail at section 

VIII.D.2. 

Rate-based and mass-based emission 

standards may incorporate the use of 

emission trading, as described below. 

The EPA anticipates the use of emission 

trading in state plans, given the 

advantages of this approach and 

comments suggesting a high degree of 

interest on the part of states, utilities, 

and independent power producers in 

the inclusion of emission trading in 

state plans.790

The EPA notes it is proposing model 

rules for both mass-based and rate-based 

emission trading programs. States could 

adopt and submit the finalized model 

rules for either emission trading 

program to meet the requirements of 

CAA section 111(d) and these emission 

guidelines. The EPA will evaluate the 

approvability of such submission, as 

with any state plan submission, through 

independent notice-and-comment 

rulemaking. The EPA notes that state 

plan submittals that adopt the finalized 

model rule may be administratively and 

technically more straightforward for the 

EPA in evaluating approvability, as the 

EPA will have determined that the 

model rule meets the applicable 

requirements of the emission guidelines 

through the process of finalization of 

such rule. 

a. Rate-based approach. The first type 

of ‘‘emission standards’’ plan approach 

a state may choose is one that uses ratebased 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 ratebased CO2 emission goal for affected 

EGUs. A plan could be designed such 

that compliance by affected EGUs 

would assure achievement of either the 

CO2 emission performance rates for 

affected EGUs or the state rate-based 

CO2 emission goal. To meet the CO2

emission performance rates for affected 

EGUs, a plan would establish separate 

rate-based emission standards for 

affected fossil fuel-fired electric utility 

steam generating units and stationary 

combustion turbines (in lb CO2/MWh) 

that are equal to or lower than the CO2

emission performance rates in the 

emission guidelines. To meet a state 

rate-based CO2 goal, a plan would 

establish a uniform rate-based emission 

standard (in lb CO2/MWh) that applies 

to all affected EGUs in the state. This 

uniform emission rate would be equal to 

or lower than the applicable state ratebased 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 ratebased CO2 goal for affected EGUs. No 

further demonstration would be 

necessary by the state to demonstrate 

that its plan would achieve the CO2

emission performance rates or the state’s 

rate-based CO2 goal. 

Alternatively, if a state chooses, it 

could apply 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.791


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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. 

792A demonstration of how a plan will achieve 

a state’s rate-based or mass-based CO2 emission goal 

is one of the required plan components, as 

described in section VIII.D.2. 

793For example, a state plan designed to meet a 

state mass-based CO2 goal for affected EGUs plus a 

new source complement could involve a massbased emission budget trading program that, under 

state law, applies to both affected EGUs, as well as 

new fossil fuel-fired EGUs. The program 

requirements for affected EGUs would be federally 

enforceable, while the program requirements for 

other fossil fuel-fired EGUs would be stateenforceable. This approach is described further in 

section VIII.J.2. 

Under this type of approach, 

therefore, the state would be required to 

include a demonstration,792 in the state 

plan submittal, that its plan would 

achieve the CO2 emission performance 

rates or applicable state rate-based CO2

goal. This demonstration would include 

a projection of the collective, weighted 

average CO2 emission rate the fleet of 

affected EGUs would achieve as a result 

of compliance with the emission 

standards in the plan. Once the plan is 

implemented, if the CO2 emission 

performance rates or applicable state 

rate-based CO2 goal are not achieved, 

corrective measures would need to be 

implemented, as described in section 

VIII.F.3. 

Under a rate-based approach, a state 

may include in its plan a number of 

provisions to facilitate affected EGU 

compliance with the emission 

standards. First, a state may encourage 

(or require) EGUs to undertake actions 

to reduce CO2 emissions at the affected 

EGU level, such as heat rate 

improvements or fuel switching. These 

measures are discussed in section VIII.I. 

Second, a state may implement a 

market-based emission trading program, 

which enables EGUs to generate and 

procure ERCs, a tradable compliance 

unit representing one MWh of electric 

generation (or reduced electricity use) 

with zero associated CO2 emissions. 

Considerations and requirements for 

rate-based trading programs are 

discussed in section VIII.K. 

ERCs would be issued by the 

administering state regulatory body. The 

state may issue ERCs to affected EGUs 

that emit below a specified CO2

emission rate, as well as for measures 

that provide substitute generation for 

affected EGUs or avoid the need for 

generation from affected EGUs. These 

ERCs may then be used to adjust the 

reported CO2 emission rate of an 

affected EGU when demonstrating 

compliance with a rate-based emission 

standard. For each submitted ERC, one 

MWh is added to the denominator of the 

reported CO2 emission rate, resulting in 

a lower adjusted CO2 emission rate. 

Eligible measures that may generate 

ERCs, as well as the accounting method 

for adjusting a CO2 emission rate, are 

discussed in section VIII.K.1. 

Requirements for rate-based emission 

trading approaches are discussed in 

section VIII.K.2. Quantification and 

verification requirements for measures 

eligible to generate ERCs are discussed 

in section VIII.K.3. 

(1) Rate-based emission standards 

based on operational or other standards. 

As discussed in further detail in 

section VIII.D.2.d.3, regarding the legal 

considerations and statutory language of 

CAA section 111(h), the EPA is 

finalizing that design, equipment, work 

practice, and operational standards 

cannot be considered to be ‘‘standards 

of performance’’ for this final rule. 

However, a state may elect to use 

emission standards for affected EGUs 

that result in a reduced CO2 lb/MWh 

emission rate for affected EGUs because 

of operational or other standards. The 

state would include in its state plan an 

emission standard that is the rate 

standard that results from the applicable 

operational or other standard. For 

example, a state might choose to 

recognize that an individual affected 

EGU has plans to retire, and those plans 

could be codified in the state plan by 

adopting an emission standard of 0 CO2

lb/MWh as of a certain date. The state 

would thus include in the state plan an 

emission standard of 0 CO2 lb/MWh for 

that affected EGU that applies after a 

specified date. 

An approvable plan could apply such 

emission standards to a subset of 

affected EGUs or all affected EGUs. As 

with any rate-based plan, the state 

would need to demonstrate that the plan 

would achieve the required level of 

emission performance for affected 

EGUs, in CO2 lb/MWh. A plan could 

also apply such emission standards to a 

subset of affected EGUs in the state 

while applying other rate-based 

emission standards to the remainder of 

affected EGUs in the state. For example, 

a plan might include an emission 

standard of 0 CO2 lb/MWh reflecting a 

retirement mandate for one or more 

affected EGUs in a state and apply a 

rate-based emission standard equal to 

the CO2 emission performance rates or 

a state’s rate-based CO2 emission goal to 

the remainder of affected EGUs. 

As with all emission standards, 

emission standards based on design, 

equipment, work practice, and 

operational standards must be 

quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These 

requirements are described in more 

detail at section VIII.D.2. 

(2) Additional considerations for ratebased approach. 

Additional considerations and 

requirements for rate-based emission 

standards state plans are addressed in 

section VIII.K. This includes the basic 

accounting method for adjusting the 

reported CO2 emission rate of an 

affected EGU, as well as requirements 

for the use of measures to adjust a CO2

emission rate, both of which are 

discussed in sections VIII.K.1 through 3. 

Such requirements include eligibility, 

accounting, and quantification and 

verification requirements (EM&V) for 

the use of CO2 emission reduction 

measures that provide substitute 

generation for affected EGUs or avoid 

the need for generation from affected 

EGUs in rate-based state plans. Section 

VIII.K.4 addresses multi-state 

coordination among rate-based emission 

trading programs. 

b. Mass-based approach. 

The second ‘‘emission standards’’ 

approach a state may elect to use is 

mass-based emission standards applied 

to affected EGUs. Under this approach, 

the plan would include federally 

enforceable emission standards for mass 

CO2 emissions from affected EGUs. The 

plan would be designed to achieve the 

mass-based CO2 goal for a state’s 

affected EGUs (see section VII) or a level 

of CO2 emissions equal to or less than 

the mass-based CO2 goal plus the new 

source complement CO2 emissions (see 

section VIII.J.2.b, Table 14).793

Under a mass-based approach, a state 

could require that individual affected 

EGUs meet a specified mass emission 

standard. Alternatively, a state could 

choose to implement a market-based 

emission budget trading program. The 

EPA envisions that the latter option is 

most likely to be exercised by states 

seeking to implement a mass-based 

emission standard approach, as it would 

maximize compliance flexibility for 

affected EGUs and enable the state to 

meet its mass goal in the most 

economically efficient manner possible. 

(1) Mass-based emission standard 

applied to individual affected EGUs. 

One pathway a state could take to 

achieve its mass-based CO2 goal would 

be to apply mass-based emission 

standards to individual affected EGUs, 

in the form of a limit on total allowable 


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794An emission allowance represents a limited 

authorization to emit, typically denominated in one 

short ton or metric ton of emissions. 

CO2 emissions. These emission 

standards would be designed such that 

total allowable CO2 emissions from all 

affected EGUs in a state are equal to or 

less than the state’s mass-based CO2

goal, or a state’s mass-based CO2 goal 

plus the new source complement CO2

emissions specified in section VIII.J.2.b, 

Table 14. The individual affected EGUs 

would be required to emit at or below 

their mass-based standard to 

demonstrate compliance. Under this 

approach, individual affected EGUs 

would be required to undertake sourcespecific measures to assure their CO2

emissions do not exceed their assigned 

emission standard. Affected EGU 

compliance with the emission standards 

prescribed under this type of massbased approach would ensure that the 

affected EGUs in a state achieve the 

state’s mass-based CO2 goal, or massbased CO2 goal plus new source 

complement. 

(2) Mass-based emission standard 

with a market-based emission budget 

trading program. 

A second pathway a state could take 

to achieve its mass-based CO2 goal 

would be to implement a market-based 

emission budget trading program. This 

type of program provides maximum 

compliance flexibility to affected EGUs, 

and as a result, may be attractive to 

states that choose to implement a massbased approach in their state plan. 

An emission budget trading program 

establishes a combined emission 

standard for a group of emission sources 

in the form of an emission budget. 

Emission allowances are issued in an 

amount up to the established emission 

budget.794 Allowances may be 

distributed to affected emission sources 

(as well as to other parties) through a 

number of different methods, including 

direct allocation to affected sources or 

auction. These allowances can be traded 

among affected sources and other 

parties. The emission standard applied 

to individual emission sources is a 

requirement to surrender emission 

allowances equal to reported emissions, 

with each allowance representing one 

ton of CO2. 

The EPA views an emission budget 

trading program as a highly efficient, 

market-based approach for reducing CO2

emissions from affected EGUs. Such 

programs include a limit on mass CO2

emissions while providing both shortterm and long-term price signals that 

encourage the owners or operators of 

affected EGUs, as well as other entities, 

to determine the most efficient means of 

achieving the mass emission standard. 

Notably, such an approach incentivizes 

actions taken at affected EGUs to reduce 

CO2 emissions, as well as the use of 

strategies such as RE and demand-side 

EE as complementary measures that 

reduce CO2 emissions. However, unlike 

under a rate-based approach, for this 

latter set of measures there is no need 

to address and describe these state 

measures in a state plan submission or 

quantify and verify the RE and EE MWh 

of generation and savings. As a result, 

a mass-based emission budget trading 

program incentivizes and recognizes a 

wide range of emission reduction 

actions while being relatively simple for 

a state to implement and administer. 

Furthermore, the EPA notes that such an 

approach still allows for a state to 

address electricity load growth, as load 

growth can be met through low- and 

zero-emitting generating resources, as 

well as avoided through demand-side 

EE and demand-side management 

(DSM) measures. 

Additional considerations and 

requirements for mass-based emission 

standards state plans are addressed in 

section VIII.J. This includes use of 

emission budget trading programs in a 

state plan, including provisions 

required for such programs (section 

VIII.J.2.a) and the design of such 

programs in the context of a state plan. 

Section VIII.J addresses program design 

approaches that ensure achievement of 

a state mass-based CO2 emission goal 

(section VIII.J.2.c), as well as how states 

can use emission budget trading 

programs with broader source coverage 

and other flexibility features in a state 

plan, such as the programs currently 

implemented by California and the 

RGGI participating states (section 

VIII.J.2.d). Section VIII.J.2.e addresses 

other 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 massbased emission standards for affected 

EGUs that result in a reduced total 

tonnage of CO2 emissions from affected 

EGUs because of operational or other 

standards. The state would include in 

its state plan an emission standard that 

is the mass standard that results from 

the applicable operational or other 

standard. For example, a state might 

choose to recognize that an individual 

affected EGU has plans to retire, and 

those plans could be codified in the 

state plan by adopting an emission 

standard of 0 total tons of CO2, as of a 

certain date. The state would thus 

include in the state plan an emission 

standard of 0 total tons of CO2 for that 

affected EGU that applies after a 

specified date. Under a mass-based 

approach, the state could also include 

an emission standard (e.g., a mass limit) 

that reflects the result of a limit on an 

affected EGU’s total operating hours 

over a specified period. 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 mass-based plan, the state 

would need to demonstrate that the plan 

would achieve the required level of 

emission performance for affected 

EGUs, in total tons of CO2. A plan could 

also apply such emission standards to a 

subset of affected EGUs in the state 

while applying other emission 

standards to the remainder of affected 

EGUs in the state. For example, a plan 

might include an emission standard of 

0 tons of CO2 for one or more affected 

EGUs, reflecting a retirement mandate 

for one or more affected EGUs in a state, 

and include the remainder of affected 

EGUs in an emission budget trading 

program. 

3. ‘‘State Measures’’ State Plan Type 

The second type of state plan is what 

we refer to as a ‘‘state measures’’ plan. 

As previously discussed, the EPA 

believes states will be able to submit 

state plans under the emission 

standards plan type, and its respective 

approaches, and achieve the CO2

emission performance rates or state ratebased or mass-based 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 and the state commitments 

approach, and in order to provide 

flexibility and choice to states that may 

wish to adopt a plan that does not place 

all the obligations on affected EGUs, the 

EPA is finalizing the state measures 

plan type in addition to the emission 

standards plan type. The EPA believes 

the state measures plan type will 

provide states with additional latitude 

in accommodating existing or planned 

programs that involve measures 

implemented by the state, or by entities 

other than affected EGUs, that result in 

avoided generation and CO2 emission 


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reductions at affected EGUs. This 

includes market-based emission budget 

trading programs that apply, in part, to 

affected EGUs, such as the programs 

implemented by California and the 

RGGI participating states in the 

Northeast and Mid-Atlantic, as well as 

RE and demand-side EE requirements 

and programs, such as renewable 

portfolio standards (RPS), EERS, and 

utility- and state-administered incentive 

programs for the deployment of RE and 

demand-side EE technologies and 

practices. The EPA believes this second 

state plan type will afford states with 

appropriate flexibility while meeting the 

statutory requirements of CAA section 

111(d). 

Measures implemented under the 

state measures plan type could include 

RE and demand-side EE requirements 

and deployment programs. This type of 

plan could align with existing state 

resource planning in the electricity 

sector, including RE and demand-side 

EE investments by state-regulated 

electric utilities. The state measures 

plan type also can accommodate 

emission budget trading programs that 

address a broader set of emission 

sources than just affected EGUs subject 

to CAA section 111(d), such as the 

programs currently implemented by 

California and the RGGI participating 

states. The EPA also notes that the state 

measures plan type could accommodate 

imposition by a state of a fee for CO2

emissions from affected EGUs, an 

approach suggested by a number of 

commenters. 

This plan type would allow the state 

to implement a suite of state measures 

that are adopted, implemented, and 

enforceable only under state law, and 

rely upon such measures in achieving 

the required level of CO2 emission 

performance from affected EGUs. The 

state measures under this plan type 

could be measures involving entities 

other than affected EGUs, or a 

combination of such measures with 

emission standards for affected EGUs, so 

long as the state demonstrates that such 

measures will result in achievement of 

a state’s mass-based CO2 goal (or massbased CO2 goal plus new source 

complement), as discussed below. The 

EPA notes that under this plan type, a 

state could also choose to include any 

emission standards for affected EGUs, 

which are required to be included in the 

plan as federally enforceable measures, 

to be implemented alongside or in 

conjunction with state measures the 

state would implement and enforce. 

For a state measures plan to be 

approvable, it must include a 

demonstration of how the measures, 

whether state measures alone or state 

measures in conjunction with any 

federally enforceable emission 

standards for affected EGUs, will 

achieve the state mass-based CO2

emission goal for affected EGUs (or 

mass-based CO2 goal plus new source 

complement). However, because the 

state measures would not be federally 

enforceable emission standards, the 

plan must also include a backstop of 

federally enforceable emission 

standards for all affected EGUs, in order 

for the state measures plan type to 

satisfy the requirement of CAA section 

111(d) that a state establish standards of 

performance for affected EGUs. This 

backstop would impose federally 

enforceable emission standards on the 

state’s affected EGUs in the case that the 

state measures fail to achieve the state 

mass-based CO2 goal. The backstop, 

discussed further below, would assure 

that the state CO2 emission goal or CO2

emission performance rates are fully 

achieved by affected EGUs in the form 

of federally enforceable emission 

standards. 

a. Requirements for state measures 

under a state measures type plan. 

Under the state measures plan type, 

state measures must be satisfactorily 

described in the supporting material for 

a state plan submittal. The supporting 

material would need to demonstrate that 

the state measures meet the same 

integrity elements that would apply to 

federally enforceable emission 

standards. Specifically, the state plan 

submittal must demonstrate that the 

state measures are quantifiable, 

verifiable, enforceable, non-duplicative 

and permanent. These requirements are 

described in more detail at section 

VIII.D.2. Under the state measures plan, 

if a state chooses to impose emission 

standards on affected EGUs, such 

emission standards must be included in 

the federally enforceable plan as they 

would be under an emission standards 

plan. 

The EPA would assess the overall 

approvability of a state measures plan 

based, in part, on the state’s satisfactory 

demonstration that the state measures, 

in conjunction with any federally 

enforceable emission standards on the 

affected EGUs that might be included in 

the plan, would result in the state plan’s 

achievement of the mass-based CO2 goal 

for the state’s affected EGUs (or massbased CO2 goal plus new source 

complement). This includes a 

demonstration of adequate legal 

authority and funding to implement the 

state plan and any associated measures. 

The EPA’s determination that such a 

plan is satisfactory would be based in 

part on whether the state measures are 

adequately described in the supporting 

documentation and the plan submittal 

demonstrates that the state measures are 

quantifiable, verifiable, enforceable, 

non-duplicative 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 massbased CO2 goal for affected EGUs (or 

mass-based CO2 goal plus new source 

complement). 

The EPA’s evaluation of the 

approvability of a state measures plan 

would also include an assessment of 

whether the backstop consisting of 

federally enforceable emission 

standards for the state’s affected EGUs 

would ensure that the required emission 

performance level is fully achieved by 

affected EGUs, in the case that the state 

measures fail to achieve the state massbased CO2 goal (or mass-based CO2 goal 

plus new source complement), or the 

state does not meet programmatic state 

measures milestones during the interim 

period. The trigger for the backstop 

must also satisfactorily provide for the 

implementation of the backstop 

emission standards. 

b. Considerations for the backstop 

included in a state measures type plan. 

As further discussed in section 

VIII.C.6.c, the EPA believes a backstop, 

composed of federally enforceable 

emission standards for the affected 

EGUs that are sufficient to achieve the 

state CO2 emission goal or the CO2

emission performance rates in the event 

that state measures do not result in the 

required CO2 emission performance, is 

necessary for the state measures plan 

type to meet the requirements of CAA 

section 111(d). The state plan must 

specify the backstop that would apply 

federally enforceable emission 

standards to the affected EGUs if the 

state measures plan does not achieve the 

anticipated level of CO2 emission 

performance by affected EGUs, or a state 

does not meet programmatic state 

measures milestones during the interim 

period. The state plan must include 

promulgated regulations (or other 

requirements) that fully specify these 

emission standard requirements, which 

must be quantifiable, verifiable, 

enforceable, non-duplicative and 

permanent. These requirements are 

described in more detail at section 

VIII.D.2. 

These federally enforceable emission 

standards must be designed such that 

compliance by affected EGUs with the 

emission standards would achieve the 

CO2 emission performance rates or 

state’s rate- or mass-based interim and 

final goals for affected EGUs. The 


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795This includes the level of emission 

performance during the interim plan periods 2022– 

2024, 2025–2027 and 2028–2029, as well as the 

performance level that would be achieved during 

every subsequent 2-year final plan performance 

period (2030–2031, and subsequent 2-year periods). 

796States may choose to establish an effective 

date for backstop emission standards that is sooner 

than 18 months. 

797 In the event a state does not implement the 

backstop as required if actual emission performance 

triggers the backstop, the EPA will take appropriate 

action. The EPA notes that as part of the proposed 

federal plan rulemaking, it is proposing a regulatory 

mechanism to call plans in the instances of 

substantial inadequacy to meet applicable 

requirements or failure to implement an approved 

plan. 

798 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. 

backstop emission standards must 

specify CO2 emission performance 

levels 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.795 If a state chose, these 

backstop emission standards could be 

based on a model rule or federal plan 

promulgated by the EPA. 

The state measures plan must specify 

the trigger and conditions under which 

the backstop federally enforceable 

emission standards would apply that is 

consistent with the requirements in the 

emission guidelines. The trigger and 

attendant conditions for deployment of 

the backstop would address the CAA 

section 111(d) requirement that states 

submit a program that provides for the 

implementation of standards of 

performance. The state measures plan 

must specify the level of emission 

performance that will be achieved by 

affected EGUs as a result of 

implementation of the state measures 

plan during the interim and final plan 

performance periods. This includes the 

level of emission performance during 

the interim plan periods 2022–2024, 

2025–2027 and 2028–2029, as well as 

the performance level that would be 

achieved during every subsequent 2- 

year final plan performance period 

(2030–2031, and subsequent 2-year 

periods). If actual CO2 emission 

performance by affected EGUs fails to 

meet the level of emission performance 

specified in the plan over the 8-year 

interim performance period (2022–2029) 

or for any 2-year final goal performance 

period, the state measures plan must 

require that the backstop federally 

enforceable emission standards would 

take effect and be applied to affected 

EGUs. Similarly, the plan must require 

that the backstop standards take effect if 

actual emission performance is deficient 

by 10 percent or more relative to the 

performance levels that the state has 

chosen to specify in the plan for the 

interim step 1 period (2022–2024) or the 

interim step 2 period (2025–2027). The 

backstop standards are also triggered if, 

at the time of the state’s annual reports 

to the EPA during the interim period, 

the state has not met the programmatic 

state measures milestones for the 

reporting period. The state measures 

plan must provide that, in the event the 

backstop is triggered, such emission 

standards would be effective within 18 

months of the deadline for the state’s 

submission of its periodic report to the 

EPA on state plan implementation and 

performance, as described in section 

VIII.D.2.c.796 797

The backstop emission standards 

must make up for the shortfall in CO2

emission performance. The shortfall 

must be made up as expeditiously as 

practicable. The state may address the 

requirement to make up for the shortfall 

in CO2 emission performance by 

submitting, as part of the final plan, 

backstop emission standards that assure 

affected EGUs would achieve the state’s 

interim and final CO2 emission goals or 

the CO2 emission performance rates for 

affected EGUs, and then later submit 

appropriate revisions to the backstop 

emission standards adjusting for the 

shortfall through the state plan revision 

process. The state may alternately 

effectuate this by submitting, along with 

the backstop emission standards, 

provisions to adjust the emission 

standards to account for any prior 

emission performance shortfall, such 

that no modification of the emission 

standards is necessary in order to 

address the emission performance 

shortfall. 

For example, assume a state measures 

plan identified a mass-based CO2

standard for affected EGUs of 100 

million tons during the interim step 1 

performance period (2022–2024), 90 

million tons during the interim step 2 

performance period (2025–2027), and 80 

million tons during the interim step 3 

performance period (2028–2029). Over 

the entire interim plan performance 

period (2022–2029), the interim massbased CO2 goal is cumulative emissions 

of 270 million tons. Assume that CO2

emissions from affected EGUs in the 

interim step 1 period were actually 115 

million tons, triggering implementation 

of the backstop. In this instance, the 

mass-based standard for affected EGUs 

implemented as part of the backstop 

during subsequent plan performance 

periods would need to ensure that 

cumulative CO2 emissions during the 

2022–2029 interim period do not exceed 

270 million tons. This could be 

achieved, for example, by implementing 

a mass standard of 75 million tons 

during the interim step 2 performance 

period (rather than the 90 million tons 

originally specified in the plan), or some 

other combination during the remaining 

interim step 2 and 3 performance 

periods.798 The emission standards 

included as the backstop in the plan 

must specify calculations for how such 

adjustments will be made. 

4. Summary of Comments on State Plan 

Approaches 

The EPA received a wide range of 

comments on the basic plan approaches 

in the proposal. Numerous commenters 

supported providing states with the 

option of implementing a rate-based or 

mass-based approach. Some 

commenters expressed concern that a 

rate-based approach would not reduce 

overall emissions, and could actually 

lead to increased emissions. The EPA 

does not 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 ratebased emission standard approach 

applied to affected EGUs. There was 

also broad support in comments for 

allowing states to pursue a mass-based 

approach in the form of mass emission 

standards on affected EGUs. The EPA is 

finalizing both of these approaches. 

The EPA received a mix of comments 

for and against the proposed portfolio 

approach, in which state requirements 

and other measures that apply to nonEGU entities would be part of a state’s 

federally enforceable state plan. 

Multiple commenters supported the 

portfolio approach because it would 

align with existing state and utility 

planning processes in the electric power 

sector, and would maximize state 

discretion and flexibility in developing 

plans. Commenters mentioned the range 

of state requirements and utility 

programs overseen by states that could 

be used under a portfolio approach and 

result in achieving the CO2 emission 

goal for affected EGUs, including state 

RPS, EERS and utility-administered EE 

programs. Commenters noted that the 

portfolio approach would provide states 

maximum flexibility to take local 

circumstances, economics and state 


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799Legal considerations with the proposed 

portfolio approach are explored in section 

VIII.C.6.d. 

800The 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. 

801The concept of a new source CO2 emission 

complement is addressed in section VIII.J.2.b. Table 

14 provides individual state new source CO2

emission complements. For a multi-state plan, a 

joint new source CO2 emission complement would 

be the sum of the individual new source CO2

emission complements in Table 14 for the states 

participating in the multi-state plan. 

802This approach also applies where a state plan 

is designed to meet a state mass-based CO2 goal 

plus a state’s new source CO2 emission 

complement. 

803States 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. 

policy into account when developing 

their plans. 

By contrast, multiple commenters 

opposed the portfolio approach. Some 

commenters questioned how a portfolio 

approach would work, and whether the 

EPA had provided sufficient detail 

explaining how such a plan approach 

could be implemented by a state. In 

particular, multiple commenters 

questioned how different state 

programs, such as utility-administered 

EE programs, could be made federally 

enforceable in practice under CAA 

section 111(d).799 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). 

5. Multi-State Plans and Multi-State 

Coordination 

The EPA views the ability of a state 

to implement an individual plan or a 

multi-state plan as a significant 

flexibility that allows a state to tailor 

implementation of its plan to state 

policy objectives and circumstances. 

The EPA sees particular value in multistate plans and multi-state coordination, 

which allow states to implement a plan 

in a coordinated fashion with other 

states. Such approaches can lead to 

more efficient implementation, lower 

compliance costs for affected EGUs and 

lower impacts on electricity ratepayers. 

Coordinated approaches also will help 

states identify and address any potential 

electric reliability impacts when 

developing plans. 

The EPA received broad support in 

comments for allowing states to 

implement multi-state plan approaches, 

and has made multiple changes in the 

final rule to address many suggestions 

outlining different approaches states 

may want to take. These changes are 

intended to provide streamlined 

approaches for multi-state coordination 

while maintaining transparency and 

assuring that the CO2 emission 

performance rates or state CO2 emission 

goals are achieved. 

The EPA is finalizing two approaches 

that allow states to coordinate 

implementation in order to meet the 

emission guidelines.800

First, states may meet the 

requirements of the emission guidelines 

and CAA section 111(d) by submitting 

multi-state plans that address the 

affected EGUs in a group of states. The 

EPA is finalizing the proposed approach 

by which multiple states aggregate their 

rate or mass CO2 goals and submit a 

multi-state plan that will achieve a joint 

CO2 emission goal for the fleet of 

affected EGUs located within those 

states (or a joint mass-based CO2 goal 

plus a joint new source CO2 emission 

complement).801

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.802 This 

approach facilitates interstate emission 

trading without requiring states to 

submit joint plans.803 The EPA 

considers these to be individual state 

plans, not multi-state plans. 

States have the option to implement 

this second approach in different ways, 

as discussed in section VIII.C.5.c. These 

different implementation options allow 

states to tailor their implementation of 

linked emission trading programs, based 

on state policy preferences, as well as 

economic and other considerations. 

These different options provide varying 

levels of state control over emission 

trading system partners and require 

varying levels of coordination in the 

course of state plan development. 

In response to comments, the EPA is 

also further clarifying how multi-state 

plans with a joint goal for affected EGUs 

may be implemented. The EPA is 

clarifying that states may participate in 

more than one multi-state plan, if 

necessary, for example, to address 

affected EGUs in states that are served 

by more than one ISO or RTO. The EPA 

is further clarifying that a subset of 

affected EGUs in a state may participate 

in a multi-state plan. These 

clarifications are discussed in section 

VIII.C.5.d. 

a. Summary of comments on multistate plans. 

Multiple commenters supported the 

EPA’s proposed approach that would 

allow states to implement a multi-state 

plan to meet a joint CO2 emission goal. 

However, a number of states commented 

that states should also be allowed to 

coordinate without aggregating multiple 

individual state goals into a single joint 

goal. Many states questioned the 

incentives that a state would have to 

aggregate its goal with other states that 

have different goals, and also noted the 

administrative complexities presented 

by states seeking to formally coordinate 

state plans with one another. 

The EPA notes that there are multiple 

incentives for states to collaborate by 

implementing a multi-state plan to meet 

an aggregated joint goal, regardless of 

the specific level of their individual 

goals, because states share grid regions 

and impacts from plan implementation 

will be regional in nature. Further, 

multiple analyses, including those by 

ISOs and RTOs, indicate that regional 

approaches could achieve state goals at 

lesser cost than individual state plan 

approaches. However, the EPA also 

recognizes the value in allowing for 

collaboration where states retain 

individual goals. These approaches 

could provide some of the benefits of a 

joint goal while reducing the 

negotiations among states necessary to 

develop a multi-state plan with a joint 

goal. As a result, the EPA has finalized 

the additional approaches described in 

section VIII.C.5 to provide for 

coordination while maintaining 

individual goals. These approaches 

would allow for interstate transfer of 

ERCs or emission allowances while 

retaining individual state goals. 


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804As 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. 

805This 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 be triggered. Under a state measures plan, 

the federally enforceable backstop emission 

standards would be triggered. See section VIII.F.3. 

806Where a multi-state plan is designed to meet 

a joint mass-based CO2 goal plus a joint new source 

CO2 emission complement, the joint new source 

CO2 emission complement would be the sum of the 

individual new source CO2 emission complements 

in section VIII.J.2.b, Table 14, for the states 

participating in the multi-state plan. 

807A 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. 

808Under this approach, a state measure could 

include, if a state chose, a multi-state emission 

trading program that is enforceable at the state 

level. 

809ERCs may only be transferred among states 

implementing rate-based emission limits. Likewise, 

emission allowances may only be transferred among 

states implementing mass-based emission limits. 

810Referred to in different programs as 

‘‘surrender,’’ ‘‘retirement,’’ or ‘‘cancellation.’’ 

811The 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. 

812Note that for mass-based plans, the 

approvability requirements for a state plan would 

differ, depending on the structure of the emission 

budget trading program included in the state plan. 

For example, approvability requirements and basic 

accounting with regard to whether a plan achieves 

a state’s mass CO2 goal would differ for emission 

budget trading programs that cover only affected 

EGUs subject to CAA section 111(d) vs. programs 

that apply to a broader set of emission sources. 

These considerations are addressed in section VIII.J. 

Many commenters suggested that 

states should be encouraged to join or 

form regional market-based programs. 

Many commenters touted the economic 

efficiency benefits of such approaches, 

and noted that such programs have 

features that support electric reliability. 

The EPA agrees with these comments, 

and notes that it encouraged such 

approaches in the proposal. While the 

EPA is not requiring states to join and/ 

or form regional market-based programs, 

we note that such programs can be 

helpful for many reasons, including 

features that support reliability. Marketbased programs allow greater flexibility 

for affected EGUs both in the short-term 

and long-term. Under a market-based 

program, affected EGUs have the ability 

to obtain sufficient allowances or credits 

to cover their emissions in order to 

comply with their emission standards. 

Additionally, we continue to encourage 

states to cooperate regionally. Regional 

cooperation in planning and reliability 

assessments is an important tool to 

meeting system needs in the most costeffective, efficient, and reliable way. 

b. Multi-state coordination through a 

joint emission goal. 

Multiple states may submit a multistate plan that achieves an aggregated 

joint CO2 emission goal for the affected 

EGUs in the participating states (or a 

joint mass-based CO2 goal plus a joint 

new source CO2 emission 

complement).804 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.805

Under this approach, a rate-based 

multi-state plan would include a 

weighted average rate-based emission 

goal, derived by calculating a weighted 

average CO2 emission rate based on the 

individual rate-based goals for each of 

the participating states and 2012 

generation from affected EGUs. A massbased 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.806

Such plans could include emission 

standards in the form of a multi-state 

rate-based or mass-based emission 

trading program.807 Alternatively, states 

could submit a multi-state plan using a 

state measures approach.808 Both 

approaches could provide for 

implementation of a multi-state 

emission trading program. 

c. Multi-state coordination among 

states retaining individual state goals. 

States that do not wish to pursue a 

joint CO2 emission goal with other states 

may pursue a second pathway to multistate collaboration. States may submit 

individual plans that will meet the CO2

emission performance rates or a state 

mass CO2 goal for affected EGUs (or 

mass-based CO2 goal plus the new 

source CO2 emission complement), but 

include implementation in coordination 

with other state plans by providing for 

the interstate transfer of ERCs or CO2

allowances, depending on whether the 

state is implementing a rate-based or 

mass-based emission trading program. 

This form of coordinated 

implementation may occur under both 

an ‘‘emission standards’’ type of plan 

and a ‘‘state measures’’ type of plan, 

where states are implementing emission 

trading programs.809 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 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,810 through either 

a joint tracking system, interoperable 

tracking systems, or an EPAadministered tracking system.811

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.812 However, the 

EPA would also assess linkages with 

other state plans, to ensure that the joint 

tracking system or interoperable 

tracking systems used to implement 

rate-based or mass-based emission 

trading programs across states are 

properly designed with necessary 

components, systems, and procedures to 

maintain the integrity of the linked 

emission trading programs. 

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


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emission performance rates in the 

emission guidelines) is discussed in 

more detail in sections VIII.J and K. 

Section VIII.J discusses coordinated 

implementation among states 

implementing individual mass-based 

emission budget trading programs and 

section VIII.K discusses coordinated 

implementation among states 

implementing individual rate-based 

emission trading programs. 

d. Multi-state plans that address a 

subset of EGUs in a state. 

The EPA is clarifying in the final 

emission guidelines that a state may 

participate in more than one multi-state 

plan. Under this approach, the state 

would identify in its submittal the 

subset of affected EGUs in the state that 

are subject to the multi-state plan or 

plans. This could involve a subset of 

affected EGUs that are subject to a 

multi-state plan, with the remainder of 

affected EGUs subject to a state’s 

individual plan. Alternatively, different 

affected EGUs in a state may be subject 

to different multi-state plans. In all 

cases, the state would need to identify 

in each specific plan which affected 

EGUs are subject to such plan, with 

each affected EGU subject to only one 

multi-state plan or subject only to the 

state’s individual plan (if relevant). 

These scenarios may occur where a 

state chooses to cover affected EGUs in 

different ISOs or RTOs in different 

multi-state plans. This will provide 

states with flexibility to participate in 

multi-state plans that address the 

affected EGUs in a respective grid 

region, in the case where state borders 

cross grid regions. 

These scenarios may also occur where 

a state is served by multiple vertically 

integrated electric utilities with service 

territories that cross state lines. This 

will provide states with flexibility to 

participate in multi-state plans that 

address the affected EGUs owned and 

operated by a utility with a multi-state 

service territory. 

6. Legal Bases and Considerations for 

State Plan Types and Approaches 

a. Legal basis for emission standards 

approach. 

The emission standards approach is 

consistent with the requirements of 

CAA section 111(d). If a state simply 

adopts the CO2 emission performance 

rates, then the corresponding rate-based 

emission standards in the state plan 

establish standards of performance for 

affected EGUs as required under section 

111(d)(1)(A). Similarly, if a state 

chooses to achieve the rate-based CO2

emission goal through rate-based 

emission standards applicable only to 

affected EGUs, or to achieve the massbased CO2 emission goal through massbased emission standards applicable 

only to affected EGUs (or, alternatively, 

to achieve the mass CO2 goal and a new 

source CO2 emission complement 

through federally enforceable massbased emission standards in 

conjunction with state enforceable 

emission standards on new sources), 

then the set of rate-based emission 

standards or the set of mass-based 

emission standards in the state plan 

establishes standards of performance for 

affected EGUs as required under section 

111(d)(1)(A). The EPA has the authority 

to approve emission standards for 

affected EGUs as part of a state plan 

under all three cases (as long as such 

emission standards meet the 

requirements of CAA section 111(d) and 

the final emission guidelines), thereby 

making such emission standards 

federally enforceable upon approval by 

the EPA. In all three cases, the emission 

standards must be quantifiable, 

verifiable, enforceable, non-duplicative 

and permanent; this ensures that the 

plan provides for implementation and 

enforcement of the standards of 

performance (i.e. the emission 

standards) as required by section 

111(d)(1)(B). Finally, as described in 

section VIII.B.7.b below, standards of 

performance may include emission 

trading. Thus, the credit and allowance 

trading that is allowed under the 

emission standards approach is 

consistent with the statutory 

requirement that the plan establish 

standards of performance. 

We note that the standard the statute 

provides for the EPA’s review of a state 

plan is whether it is ‘‘satisfactory.’’ We 

interpret a ‘‘satisfactory’’ plan as one 

that meets all applicable requirements 

of the CAA, including applicable 

requirements of these guidelines. Some 

commenters suggested that 

‘‘satisfactory’’ should be taken to mean 

something less (such as mostly or 

substantially meeting requirements) but 

the structure of 111(d) shows otherwise. 

When a state plan is unsatisfactory, 

section 111(d)(2) gives the EPA the 

‘‘same’’ authority to promulgate a 

federal plan as the EPA has under 

section 110(c). Under section 110(c), the 

EPA has authority to promulgate a 

federal implementation plan if a SIP 

does not comply with all CAA 

requirements (see sections 110(k)(3) and 

110(l)). 

For example, if an emission standards 

type plan includes an emission standard 

that is unenforceable due to defective 

rule language, then the plan is not 

satisfactory because it does not comply 

with the guideline requirement that 

emission standards must be enforceable. 

On the other hand, if a state plan 

complies with all applicable 

requirements of the CAA (including 

these guidelines), then the EPA must 

approve it as satisfactory. This is true 

even if the emission standards in the 

state plan are more stringent than the 

minimum requirements of these 

guidelines, or the state plan achieves 

more emission reductions than required 

by these guidelines. This follows from 

section 116 of the CAA as interpreted by 

the U.S. Supreme Court in Union Elec. 

Co. v. EPA, 427 U.S. 246, 263–64 (1976). 

b. Legal basis for emissions trading in 

state plans. 

There are three legal considerations 

with respect to emissions trading in 

state plans. First, we explain how the 

definition of ‘‘standard of performance’’ 

in section 111(a)(1) allows section 

111(d) plans to include standards of 

performance that authorize emissions 

trading. Second, we explain how the 

EPA interprets the phrase ‘‘provides for 

implementation and enforcement of 

[the] standards of performance’’ in the 

context of a rate-based ERC trading 

program. Third, we give a similar 

explanation of the EPA’s interpretation 

of the same phrase in the context of a 

mass-based allowance trading program. 

(1). In the proposal, the EPA proposed 

that CAA section 111(d) plans may 

include standards of performance that 

authorize emissions averaging and 

trading. 79 FR 34830, 34927/1 (June 18, 

2014). We are finalizing that states may 

include the use of emission trading in 

approvable state plans. 

For purposes of this legal discussion, 

in the case of an emission limitation 

expressed as an emission rate, trading 

takes the form of buying or selling ERCs 

that an affected EGU may generate if its 

actual emission rate is lower than its 

allowed emission rate or that an eligible 

resource may generate. In the case of an 

emission limitation expressed as a massbased limit, trading takes the form of 

buying or selling allowances. 

As quoted in full above, the definition 

of ‘‘standard of performance’’ under 

CAA section 111(a)(1) is 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.’’ 

Both an emission rate that may be met 

through tradable ERCs, and a mass limit 

requirement that emissions not exceed 

the number of tradable allowances 

surrendered by an affected source, 

qualify as a ‘‘standard for emissions.’’ 

The term ‘‘standard’’ is not defined, but 

its everyday meaning is a rule or 


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813E.g., ‘‘Something that is set up and established 

by authority as a rule for the measure of quantity, 

weight, value, or quality.’’ Webster’s Third New 

International Dictionary 2223 (1967); see also The 

American College Dictionary (C.L. Barnhart, ed. 

1970) (‘‘an authoritative model or measure’’). 

814 70 FR 28606, 28616–17 (May 18, 2005). 

815 60 FR 65387, 6540/2 (Dec. 19, 1995). 

requirement,813 which, under the only 

(or at least a permissible) reading of the 

provision, would include an emission 

rate that may be met through tradable 

ERCs and a requirement to retire 

tradable allowances. 

Treating a tradable emission rate or 

mass limit requirement as a ‘‘standard of 

performance’’ is consistent with past 

EPA practice. In the Clean Air Mercury 

Rule, promulgated in 2005, the EPA 

established tradable mass limits as the 

emission guidelines for certain air 

pollutants from fossil fuel-fired EGUs, 

and explained that a tradable mass limit 

qualifies as a ‘‘standard for 

emissions.’’ 814 In addition, in the 1995 

Municipal Solid Waste (MSW) 

Combustor rule the EPA authorized 

emission trading by sources.815

It should be noted that CAA section 

302(l) includes another definition of 

‘‘standard of performance,’’ which is ‘‘a 

requirement of continuous emission 

reduction, including any requirement 

relating to the operation or maintenance 

of a source to assure continuous 

emission reduction.’’ As described 

above, section 111(d) contains its own, 

more specific definition of ‘‘standard of 

performance,’’ which a tradable 

emission rate or mass limit satisfies. 

Whether or not section 302(l) applies in 

light of section 111(d)’s more specific 

definition, a tradable emission rate or 

mass limit also meets section 302(l)’s 

requirements. A tradable emission rate 

applies continuously in that the source 

is under a continuous obligation to meet 

its emission rate, and that is so 

regardless of the averaging time, e.g., a 

rate that must be met on an annual 

basis. Similarly, a mass limit 

requirement implemented through the 

use of allowances applies continuously 

in that the source is continuously under 

an obligation to assure that at the 

appropriate time, its emissions will not 

exceed the allowances it will surrender. 

In this respect, a tradable emission rate 

or mass limit requirement is similar to 

a non-tradable emission rate that must 

be met over a specified period, such as 

one year. In all of these cases, a source 

is continuously subject to its 

requirement although it may be able to 

emit at different levels at different 

points in time. It should also be noted 

that a tradable emission rate or mass 

limit requirement is appropriate for CO2

emissions, the air pollutant covered by 

this rule, because the environmental 

effects of CO2 emissions are not 

dependent on the location of the 

emissions. 

(2). In our final rule, we are 

prescribing certain specific 

requirements for trading systems for 

ERCs in a rate-based approach. These 

specific requirements are in addition to 

the generic requirements for any state 

plan (see section VIII.D.2.d below for 

the legal basis for the generic 

components for state plans) and are 

intended to ensure the integrity of the 

ERC trading system. The integrity of the 

trading system is key to ensuring that a 

state plan provides for implementation 

and enforcement of the standards of 

performance, as required by section 

111(d)(1)(B). Requirements relating to 

ERCs in a rate-based trading system, and 

allowances in a mass-based system, 

must also be submitted as federally 

enforceable components of the state 

plan, as such requirements provide for 

the implementation and enforcement of 

a tradable emission rate or mass limit 

for an affected EGU. 

However, as described in section 

VIII.C.6.d, the EPA has legal concerns 

regarding whether federally enforceable 

requirements under a CAA section 

111(d) state plan can be imposed on 

entities other than affected EGUs. It is 

important to note that the use of ERCs 

and inclusion of state plan requirements 

regarding a rate-based trading system, 

and the use of allowances and inclusion 

of state plan requirements regarding a 

mass-based trading system, does not run 

afoul of these legal concerns, as neither 

the requirements of section 111(d) nor 

of the federally enforceable state plan in 

either case extend to non-EGU 

generators or third-party verifiers of 

such compliance units. 

(3). In our final rule, we are 

prescribing certain specific 

requirements for trading systems for 

allowances in a mass-based approach. 

These specific requirements are in 

addition to the generic requirements for 

any state plan (see section VIII.D.2.d 

below for the legal basis for the generic 

requirements for state plans) and are 

intended to ensure the integrity of the 

allowance trading system. The integrity 

of the trading system is key to ensuring 

that a state plan provides for 

implementation and enforcement of the 

standards of performance. 

c. Legal basis for state measures plan 

type. 

The EPA believes the state measures 

plan type is consistent with CAA 

section 111(d). Section 111(d)(1) 

requires a state to submit a plan that 

‘‘(A) establishes standards of 

performance for any existing source for 

[certain] air pollutant[s] . . . and (B) 

provides for the implementation and 

enforcement of such standards of 

performance.’’ Section 111(d)(2)(A) 

indicates that the EPA must approve the 

state plan if it is ‘‘satisfactory.’’ 

For states that choose to adopt and 

submit a state measures plan, such state 

must submit a state plan that includes 

standards of performance for CO2

emissions from affected EGUs in the 

form of a federally enforceable backstop 

in order to meet the requirements of 

section 111(d). Section 111(d) 

unambiguously requires a state to 

submit a plan that establishes standards 

of performance for certain sources, but 

does not mandate when such standards 

of performance must be in effect or 

implemented in order to meet 

applicable compliance deadlines. 

Instead, Congress has delegated to the 

EPA the determination of the 

appropriate effective date of standards 

of performance submitted under state 

plans to meet the requirements of 

section 111(d). In other words, where 

the statute is silent, the EPA has 

authority to provide a reasonable 

interpretation. The EPA’s interpretation 

is that for states that submit state plans 

establishing standards of performance 

under section 111(d), the effective date 

of such standards of performance may 

be later in time, perhaps indefinitely, for 

a number of reasons and under certain 

conditions. A key condition is that the 

state plan provides for the achievement 

of the required reduction by means 

other than the standards of performance 

on the timetable required by the BSER, 

with provision for federally enforceable 

standards of performance to be 

implemented if those other means fall 

short. The EPA believes it is reasonable 

to defer the effective date for standards 

of performance for affected EGUs as 

long as affected EGU CO2 emissions are 

projected to achieve, and do achieve, 

the requisite state goal. 

Additionally, under the state 

measures plan type, if a state chooses to 

impose emission standards for the 

affected EGUs in conjunction with state 

measures that apply to other entities for 

any period prior to the triggering of the 

backstop, this final rule requires such 

emission standards to be submitted as 

federally enforceable measures included 

in the state plan. The EPA believes this 

is appropriate to help ensure the 

performance of a state measures plan 

will meet the requirements of this final 

rule. Section 111(d) clearly authorizes 

states to impose, and the EPA to 

approve, federally enforceable emission 

standards for affected EGUs. Though 

federally enforceable emission 

standards for affected EGUs in a state 


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measures plan themselves would not 

necessarily achieve the requisite state 

goals, the EPA is authorized to approve 

state plans when they satisfactorily meet 

applicable requirements. The EPA can 

evaluate whether a state measures plan 

is satisfactory by determining whether 

any federally enforceable emission 

standards for affected EGUs in 

conjunction with state measures on 

other entities will result in the 

achievement of the requisite emissions 

performance level. As previously 

explained in this final rule, the 

performance rates and the state goals are 

the arithmetic expression of BSER as 

applied across affected EGUs in a state 

as a source category. In a state measures 

plan, the evaluation of whether a state 

measures plan is satisfactory goes to 

evaluating both the state measures and 

any federally enforceable emission 

standards on the affected EGUs to 

determine whether the plan as a whole 

will result in the affected EGUs 

achieving the applicable goals that 

reflect BSER. 

Section 111(d)(1)(B) also requires a 

state to submit a program that provides 

for the implementation and enforcement 

of the applicable standards of 

performance. Under the state measures 

approach, this requirement regarding 

implementation is satisfied in part by 

the submission of an approvable trigger 

mechanism for the backstop and 

appropriate monitoring, reporting and 

recordkeeping requirements. The trigger 

mechanism provides for the 

‘‘implementation’’ of the backstop, i.e., 

the standards of performance, by putting 

the backstop into effect once the 

associated trigger is deployed. In other 

words, when the CO2 performance level 

under a state plan exceeds the trigger as 

described in section VIII.C.4.b, the 

emission standards that were submitted 

as the federally enforceable backstop 

and any attendant requirements must be 

implemented and in effect. The 

statutory requirement under CAA 

section 111(d)(2) regarding enforcement 

is also satisfied under the state measures 

plan type by the state submitting 

standards of performance sufficient to 

meet the requisite emission performance 

rates or state goal, in the form of the 

backstop, for inclusion as part of the 

federally enforceable state plan. 

Additionally, by requiring states that 

choose to impose emission standards on 

affected EGUs under the state measures 

approach to submit such emission 

standards for inclusion in the federally 

enforceable plan, this requirement 

further provides for implementation and 

enforcement as required by the statute. 

Regulating the affected EGUs through 

federally enforceable emission 

standards themselves in conjunction 

with any state measures the state 

chooses to rely upon further assures the 

likelihood of the affected EGUs 

achieving the state goals as required 

under this rule and section 111(d). 

The state measures plan is a variation 

of the proposed portfolio approach in 

that both plan types allow the state to 

rely upon measures that impose 

requirements on sources other than 

affected EGUs in meeting the requisite 

state CO2 emission goal. The state 

measures plan type is also a variation of 

the proposed state commitment 

approach in that the measures involving 

entities other than affected EGUs are not 

included as part of the federally 

enforceable 111(d) state plan, but the 

state may rely upon such measures that 

have the effect of reducing CO2

emissions from affected EGUs as a 

matter of state law. The EPA took 

comment on the proposed portfolio 

approach and state commitment 

approach, and on the utilization of 

measures on entities other than affected 

EGUs in meeting the requirements of the 

emission guidelines and CAA section 

111(d). With respect to the proposed 

state commitment approach, the EPA 

received comments recommending that 

the EPA require a federally enforceable 

backstop with emission standards 

sufficient to achieve the requisite CO2

emission performance. The backstop 

component the EPA is finalizing as part 

of the state measures plan type is 

consistent with the EPA’s statements in 

the proposal regarding states’ 

obligations under section 111(d) to 

establish emission standards for affected 

EGUs, as the backstop contains federally 

enforceable emission standards for 

affected EGUs that will achieve the 

requisite CO2 emission performance, 

and is consistent with comments 

received regarding the proposed state 

commitment approach. 

The state measures plan type the EPA 

is finalizing is also a logical outgrowth 

of the comments received on the 

proposed portfolio approach. As further 

explained below, legal questions remain 

as to whether state plans under section 

111(d) can include federally enforceable 

measures that impose requirements on 

sources other than affected EGUs. 

However, a number of commenters and 

stakeholders expressed robust support 

for the ability to rely on measures and 

programs that do not impose 

requirements on affected EGUs 

themselves through plan types such as 

the proposed portfolio and state 

commitment approaches. The EPA is 

reasonably interpreting 111(d) as 

authorizing the state measures plan 

type, and believes this plan type is also 

responsive to, and accommodating of, 

states and stakeholders who have 

expressed the importance of being able 

to rely upon various measures that have 

the effect of reducing CO2 emissions 

from affected EGUs. The EPA is 

finalizing the state measures plan type 

upon careful consideration of statutory 

requirements and comments received 

based on the proposed portfolio 

approach and state commitment 

approach. 

The EPA additionally notes that the 

state measures plan type is not 

precluded by the recent Ninth Circuit 

Court of Appeals’ decision in 

Committee for a Better Arvin et al. v. US 

EPA et al., Nos. 11–73924 and 12–71332 

(May 20, 2015). The court held that the 

EPA violated the CAA by approving a 

California SIP which relied on emission 

reductions from state-only mobile 

source standards (‘‘waiver measures’’) 

without including those standards in 

the SIP. The court first looked at the 

plain language of section 110(a)(2)(A) of 

the CAA, which states that SIPs ‘‘shall 

include’’ the emission limitations and 

other control measures on which a state 

relies to comply with the CAA. The 

court then stated that the EPA’s action 

was also inconsistent with the structure 

of the CAA. The EPA has the primary 

responsibility to protect the nation’s air 

quality, but in the court’s view, the EPA 

itself would be unable to enforce the 

state-only standards. In addition, the 

court stated that the EPA’s action was 

inconsistent with citizens’ right to 

enforce SIP provisions under section 

304. 

There are a number of reasons why 

this decision does not preclude the state 

measures plan type. The Ninth Circuit’s 

textual analysis does not apply here, as 

the language of section 110(a)(2)(A) does 

not control for 111(d) state plans. 

Section 111(d)(1) requires state plans to 

‘‘establish standards of performance’’ 

and to ‘‘provide for implementation and 

enforcement’’ of the standards of 

performance, but, unlike section 

110(a)(2)(A), section 111(d) does not 

specifically say that every emission 

reduction measure must be ‘‘included’’ 

in the state plan and be made federally 

enforceable. Even if section 111(d) did 

impose such requirements, the state 

measures approach satisfies them 

because the trigger is included in the 

plan as a federally enforceable 

implementation measure, and the 

backstop included in the plan also 

contains standards of performance that 

reflect the BSER and are federally 

enforceable once they are triggered. 

The Ninth Circuit’s structural analysis 

also does not apply. The availability of 

the trigger and backstop gives the EPA 


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816Such measures include, for example, in this 

rule, requirements for ERCs. 

817The 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 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.’’ 

and citizens a federally enforceable 

route to ensure that all necessary 

emission reductions take place in order 

to achieve the standards of performance. 

This is markedly different than the 

state-only standards, where according to 

the Ninth Circuit, the EPA and citizens 

had no route to ensure that all necessary 

emission reductions took place in order 

to attain the NAAQS. In addition, case 

law suggests that federal enforceability 

for every requirement may not be 

necessary when there are sufficient 

federally enforceable requirements to 

satisfy the statute, see National Mining 

Ass’n v. United States EPA, 59 F.3d 

1351 (D.C. Cir. 1995); in this case 

federal enforceability for the state-only 

measures is not necessary to meet the 

statutory requirements of section 

111(d)(1) as the federally enforceable 

trigger and backstop are sufficient. 

d. Legal considerations with proposed 

portfolio approach. 

The EPA is not finalizing the portfolio 

approach that was included in the 

proposed rulemaking, 79 FR 34830, 

34902 (June 18, 2014). In the proposal, 

the EPA noted that the portfolio 

approach raised legal questions. 79 FR 

34830, 34902–03. A number of 

commenters stated that the portfolio 

approach is unlawful because it exceeds 

the limitations that section 111(d)(1) 

places on state plans. Upon further 

review, we agree with these comments. 

Section 111(d)(1) provides that state 

plans shall ‘‘establish[] ‘‘standards of 

performance for any existing source’’ 

and ‘‘provide[] for the implementation 

and enforcement of . . . standards of 

performance’’ under CAA section 

111(d)(1). Although in the proposal we 

identified possible interpretations of 

section 111(d)(1) that could justify the 

proposed portfolio approach, after 

reviewing the comments, we are not 

adopting those interpretations. Because 

section 111(d)(1) specifically requires 

state plans to include only (A) standards 

for emissions imposed on affected 

sources and (B) measures that 

implement and enforce such 

standards,816 we interpret it as allowing 

federal enforceability only of 

requirements or measures that are in 

those two specifically required 

provisions. We therefore do not 

interpret the term ‘‘implementation of 

. . . such standards of performance’’ to 

authorize the EPA to approve state plans 

with obligations enforceable against the 

broad array of non-emitting entities that 

would have been implicated by the 

portfolio approach. Thus, the EPA is not 

finalizing the portfolio approach, and in 

the event that states submit such 

measures to the EPA for inclusion in the 

state plan, the EPA would not approve 

them into the state plan and therefore 

would not make them federally 

enforceable. 

We note that section 111(d) limits on 

federal enforceability of requirements 

against non-affected sources do not 

imply that the BSER cannot be based on 

actions by non-affected sources. As 

discussed in section V, the BSER may be 

based on the ability of owners/operators 

of affected sources to engage in 

commercial relationships with a wide 

range of other entities, from the vendors, 

installers, and operators of air pollution 

control equipment to, in this 

rulemaking, owners/operators of RE. 

The EPA notes it is also not finalizing 

the proposed state commitment 

approach or state crediting approach. 

The EPA believes the finalized state 

measures plan type provides states with 

the same flexibilities as would have 

been allowed under these two proposed 

approaches, and does so in a way that 

is legally supportable by the CAA. 

Therefore, the EPA does not believe it 

necessary to finalize the state 

commitment approach or state crediting 

approach. 

e. Legal basis for multi-state plans. 

While nothing in section 111(d)(1) 

explicitly authorizes either states to 

adopt and submit multi-state plans, or 

the EPA to approve them as satisfactory, 

nothing in section 111(d)(1) explicitly 

prohibits it, either. In addition, nothing 

in section 111(d)(2)(A)’s standard of 

‘‘satisfactory’’ prohibits the EPA from 

considering multi-state plans as 

satisfactory. There is thus a gap that the 

EPA may reasonably fill. 

In light of the purpose of these 

emission guidelines, to reduce 

emissions of a pollutant that globally 

mixes in the stratosphere, and the 

mechanisms to reduce those emissions, 

which may have beneficial effects across 

state lines, it is reasonable to allow for 

multi-state plans. Thus, our gap-filling 

interpretation of section 111(d) in this 

context is reasonable. 

D. State Plan Components and 

Approvability Criteria 

1. Approvability Criteria 

In the ‘‘Criteria for Approving State 

Plans’’ section of the preamble to the 

June 2014 proposal (section VIII.C), the 

EPA proposed the following as 

necessary components of an approvable 

state plan: 

1. The plan must contain enforceable 

measures that reduce EGU CO2

emissions; 

2. The projected CO2 emission 

performance by affected EGUs must be 

equivalent to or better than the required 

CO2 emission performance level in the 

state plan; 

3. The EGU CO2 emission 

performance must be quantifiable and 

verifiable; 

4. The plan must include a process for 

state reporting of plan implementation, 

CO2 emission performance outcomes, 

and implementation of corrective 

measures, if necessary. 

After reviewing the comments we 

received concerning the approvability 

criteria, the EPA has decided against 

maintaining the four proposed 

approvability criteria separately from 

the list of components required for an 

approvable plan, which may be 

confusing and potentially redundant. 

The EPA has determined that a 

satisfactory state plan that meets the 

required plan components discussed 

below will inevitably meet the proposed 

approvability criteria. The EPA, 

therefore, has incorporated the proposed 

approvability criteria into the section 

titled ‘‘Components of a state plan 

submittal’’ (section VIII.D.2 below). 

There is no functional change in the 

approvability criteria or the components 

of a state plan addressed in the 

proposal; they are simply combined and 

this change does not have a substantive 

effect on state plan development or 

approval. 

Under the proposed ‘‘Enforceable 

Measures’’ criterion (section VIII.C.1 of 

the proposal preamble), the EPA 

specifically requested comment on the 

appropriateness of applying existing 

EPA guidance on enforceability to state 

plans under CAA section 111(d), 

considering the types of entities that 

might be included in a state plan.817

The EPA also requested comment on 

whether the agency should provide 

guidance on enforceability 

considerations related to requirements 

in a state plan for entities other than 

affected EGUs, and if so, what types of 

entities. Comments received strongly 

suggested that the EPA provide 

guidance on enforceability 

considerations for non-EGU affected 

entities, particularly for RE and EE. 

Comments also requested additional 

guidance specific to this rulemaking, 

including examples of enforceable 

measures for specific activities, such as 


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818 If applicable, this plan component must also 

identify if the plan is being submitted as a ‘‘readyfor-interstate-trading’’ plan, as discussed in section 

VIII.J.3 and VIII.K.4. 

solar thermal technologies, waste heat 

recovery, net-metering energy savings 

and state RPS. 

These enforcement considerations 

arose primarily under the proposed 

portfolio approach for state plans, 

which would have allowed state plans 

to include federally enforceable 

measures that apply to entities that are 

not affected EGUs. In this action, the 

EPA is finalizing the state measures 

approach instead of the portfolio 

approach, under which a state can rely 

upon measures that are not federally 

enforceable as long as the plan also 

includes a backstop of federally 

enforceable emission standards that 

apply to affected EGUs. As explained in 

depth in section VIII.C, if the state is 

adopting the state measures approach, 

the state plan submittal will need to 

specify, in the supporting materials, the 

state-enforceable measures that the state 

is relying upon, in conjunction with any 

federally enforceable emission 

standards for affected EGUs, to meet the 

emission guidelines. As part of the state 

measures approach, the EPA is 

finalizing a requirement for a federally 

enforceable backstop, which requires 

the affected EGUs to meet emission 

standards that fully achieve the CO2

emission performance rates or the state’s 

CO2 emission goal if the state measures 

do not meet the state’s mass-based CO2

emission goal. Because the EPA is not 

finalizing the portfolio approach, which 

would have allowed states to include 

federally enforceable measures in a state 

plan that apply to entities that are not 

affected EGUs, the agency is not 

providing additional guidance on 

federal enforceability of measures that 

might apply to such entities. As 

proposed, we are requiring that state 

plans include a demonstration that plan 

measures are enforceable, which for 

emission standards plan types is 

discussed in section VIII.D.2.b.3 below 

and for state measures plan types is 

discussed in section VIII.D.2.c.6 below. 

Commenters also requested that the 

EPA allow states to rely on provisions 

with flexible compliance mechanisms in 

state plans and clarify how to address 

flexible compliance mechanisms when 

demonstrating achievement of a state 

CO2 emission goal. Additionally, a 

commenter requested that the 

enforceability mechanisms that the EPA 

requires in state plans should support 

existing programs, as well as new 

programs in other states, by minimizing 

program changes required purely to 

conform with federal requirements, 

while still providing enough additional 

program review and accounting to 

ensure that CO2 emission reductions are 

achieved. These and related comments 

contributed to the EPA’s decision to 

finalize the option for states to submit 

a state measures plan, which would be 

comprised, at least in part, of measures 

implemented by the state that are not 

included as federally enforceable 

components of the plan, with a backstop 

of federally enforceable emission 

standards for affected EGUs that fully 

meet the emission guidelines and that 

would be triggered if the plan failed to 

achieve the CO2 emission performance 

levels specified in the plan on schedule. 

For more information on the state 

measures plan approach, see section 

VIII.C.3 of this preamble above. 

2. Components of a State Plan Submittal 

In this action, the EPA is finalizing 

that a state plan submittal must include 

the components described below. As a 

result of constructive comments 

received from many commenters and 

additional considerations, the EPA is 

finalizing state plan components that 

are responsive to that input and are 

appropriate for the types of state plans 

allowed in the final emission 

guidelines. A state plan submittal must 

also be consistent with additional 

specific requirements elsewhere in this 

final rule and with the EPA 

implementing regulations at 40 CFR 

60.23–60.29, except as otherwise 

specified by this final rule. These 

requirements apply to both individual 

state plan submittals and multi-state 

plan submittals. When a state plan 

submittal is approved by the EPA, the 

EPA will codify the approved CAA 

section 111(d) state plan in 40 CFR part 

62. Section VIII.D.3 discusses the 

components of a state plan submittal 

that would be codified as the state CAA 

section 111(d) plan when the state plan 

submittal is approved by the EPA. 

The EPA is finalizing that states can 

choose to meet the emission guidelines 

through one of two types of state plans: 

an emission standards plan type or a 

state measures plan type. A state 

pursuing the emission standards plan 

type may opt to submit a plan that 

meets the CO2 emission performance 

rates for affected EGUs or meets the 

state rate-based or mass-based CO2

emission goal for affected EGUs. A state 

implementing a state measures 

approach plan type must submit a plan 

where the state measures, in 

conjunction with any emission 

standards on the affected EGUs, result 

in achievement of the state mass-based 

CO2 goal for affected EGUs. The 

backstop required to be submitted as 

part of a state measures plan may 

achieve the CO2 emission performance 

rates for affected EGUs or the state ratebased or mass-based CO2 emission goal. 

The content of the state plan submittal 

will vary depending on which plan type 

the state decides to adopt. States that 

choose to participate in multi-state 

plans must adequately address plan 

components that apply to all 

participating states in the multi-state 

plan. 

The rest of this section covers 

components that are required for all 

types of plans, as well as components 

specific to each specific type of plans. 

Section VIII.D.2.a addresses the 

components required for all plan 

submittals. Section VIII.D.2.b addresses 

the additional components required for 

submittals under the emission standards 

plan type. Section VIII.D.2.c addresses 

additional components required for 

submittals under the state measures 

plan type. 

a. Components required for all state 

plan submittals. 

The EPA is finalizing requirements 

that a final plan submittal must contain 

the following components, in addition 

to those in either section VIII.D.2.b (for 

the emission standards plan type) or 

VIII.D.2.c (for the state measures plan 

type) of this section. 

(1) Description of the plan approach 

and geographic scope. 

The description of the plan type must 

indicate whether the state will meet the 

emission guidelines on an individual 

state basis or jointly through a multistate plan, and whether the state is 

adopting an emission standards plan 

type or a state measures plan type. For 

multi-state plans this component must 

identify all participating states and 

geographic boundaries applicable to 

each component in the plan submittal. 

If a state intends to implement its 

individual plan in coordination with 

other states by allowing for the 

interstate transfer of ERCs or emission 

allowances, such links must also be 

identified.818

(2) Applicability of state plans to 

affected EGUs. 

The state plan submittal must list the 

individual affected EGUs that meet the 

applicability criteria of 40 CFR 60.5845 

and provide an inventory of CO2

emissions from those affected EGUs for 

the most recent calendar year prior to 

plan submission for which data are 

available. 

(3) Demonstration that a state plan 

will achieve the CO2 emission 

performance rates or state CO2 emission 

goal. 

A state plan submittal must 

demonstrate that the federally 


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819State plans may meet the CO2 emission 

performance rates in the emission guidelines during 

the interim plan performance step periods, or assign 

different interim step CO2 emission performance 

rates, provided the CO2 emission performance rates 

in the emission guidelines are achieved during the 

full interim period. Likewise, a state plan may meet 

the interim step state CO2 emission goals in the 

emission guidelines or establish different interim 

step CO2 emission levels, provided the state interim 

CO2 goal is achieved during the full interim period. 

820For simplicity, the EPA refers here to state 

measures under a state measures plan as being 

included ‘‘in the state plan’’ although such stateenforceable 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. 

821A state’s EPA-specified mass CO2 emission 

budget is the state’s mass-based CO2 goal for 

affected EGUs plus the EPA-specified new source 

CO2 emission complement. See section VIII.J.2.b. 

enforceable emission standards for 

affected EGUs and/or state measures are 

sufficient to meet either the CO2

emission performance rates or the state’s 

CO2 emission goal for affected EGUs in 

the emission guidelines for the interim 

and final plan performance periods. 

This includes during the interim period 

of 2022–2029, including the interim 

step 1 period (2022–2024); interim step 

2 period (2025–2027); and interim step 

3 period (2028–2029) period, as well as 

during the final period of 2030–2031 

and subsequent 2-year periods.819 A 

demonstration of CO2 emission 

performance is required through 2031. 

For the post-2031 period, the 

demonstration requirement may be 

satisfied by showing that emission 

standards or state measures on which 

the demonstration through 2031 is 

based are permanent and will remain in 

place. As discussed in more detail in 

section VIII.J, states adopting a plan 

based upon a mass-based state CO2

emission goal must demonstrate that 

they have addressed the risk of potential 

emission leakage in their mass-based 

state plan. 

The type of demonstration of CO2

emission performance and 

documentation required for such a 

demonstration in a state plan submittal 

will vary depending on how the CO2

emission standards for affected EGUs 

and/or state measures in a state plan are 

applied across the fleet of affected EGUs 

in a state, as discussed below.820

(a) State plan type designs that 

require a projection of CO2 emission 

performance. Whether a projection of 

affected EGU CO2 emission performance 

must be included in a state plan 

submittal depends on the design of the 

state plan. The following plan designs 

do not require a projection of CO2

emission performance by affected EGUs 

under the state plan because they ensure 

that the CO2 emission performance rates 

or state rate-based or mass-based CO2

goals are achieved when affected EGUs 

comply with the emission standards: 

• State plan establishes separate rate-based 

CO2 emission standards for affected fossil 

fuel-fired electric utility steam generating 

units and stationary combustion turbines (in 

lb CO2/MWh) that are equal to or lower than 

the CO2 emission performance rates in the 

emission guidelines during the interim and 

final plan performance periods. 

• State plan establishes a single rate-based 

CO2 emission standard for all affected EGUs 

that is equal to or lower than the state’s ratebased CO2 goal in the emission guidelines 

during the interim and final plan 

performance periods. 

• State plan establishes mass-based CO2

emission standards for affected EGUs that 

cumulatively do not exceed a state’s massbased CO2 goal in the emission guidelines 

during the interim and final plan 

performance periods. 

• State plan establishes mass-based CO2

emission standards for affected EGUs that, 

together with state enforceable limits on mass 

emissions from new EGUs, cumulatively do 

not exceed the state’s EPA-specified mass 

CO2 emission budget 821 in the emission 

guidelines during the interim and final plan 

performance periods. 

All other state plan designs must 

include a projection of CO2 emission 

performance by affected EGUs under the 

state plan. 

For example, if a state chooses to 

apply rate-based CO2 emission 

standards to individual affected EGUs, 

or to subcategories of affected EGUs 

(such as fossil fuel-fired electric utility 

steam generating units and stationary 

combustion turbines), at a lb CO2/MWh 

rate that differs from the CO2 emission 

performance rates or the state’s ratebased CO2 goal in the emission 

guidelines, then a projection is required. 

Also, if a state chooses to implement a 

mass-based program including both 

affected EGUs and new EGUs, but with 

total allowable emissions in excess of 

the presumptively approvable EPAspecified mass CO2 emission budget for 

that state, the state must provide a 

projection of CO2 emission performance. 

Likewise, if a state chooses a state 

measures state plan approach, a 

projection of CO2 emission performance 

is required. 

(b) Methods and tools. A satisfactory 

demonstration of the future CO2

emission performance of affected EGUs 

must use technically sound methods 

that are reliable and replicable. A state 

plan submittal must explain how the 

projection method and/or tool works 

and why the method and/or tool chosen 

is appropriate considering the type of 

emission standards and/or state 

measures included (or relied upon, in 

the case of state measures) in a state 

plan. The results of the demonstration 

must be reproducible using the 

documented assumptions described in 

the state plan submittal. The method 

and projection of EGU generation and 

CO2 emissions can differ from the EPA’s 

forecast in the RIA. The EPA received 

comments on whether it would require 

specific modeling tools and input 

assumptions. Commenters raised 

concerns that the EPA may require 

states to use proprietary models, and 

that states do not have the financial 

resources to use such models. The EPA 

is not requiring a specific type of 

method or model, as long as the one 

chosen uses technically sound methods 

and tools that establish a clear 

relationship between electricity grid 

interactions and the range of factors that 

impact future EGU economic behavior, 

generation, and CO2 emissions. The EPA 

will assess whether a method or tool is 

technically sound based on its 

capability to represent changes in the 

electric system commensurate to the set 

of emission standards and state 

measures in a state plan while 

accounting for the key parameters 

specified in section VIII.D.2.a.(3)(c) 

below. Including a base case CO2

emission projection in the state plan 

submittal (i.e., one that does not include 

any federally enforceable CO2 emission 

standards included in a plan or stateenforceable measures referenced in a 

plan submittal), will help facilitate the 

EPA’s assessment of the CO2 emission 

performance projection. Methods and 

tools could range from applying future 

growth rates to historical generation and 

emissions data, using statistical 

analysis, or electric sector energy 

modeling. 

(c) Required documentation of 

projections. When required to provide a 

CO2 emission performance projection, 

the state must also provide 

comprehensive documentation of 

analytic parameters for the EPA to 

assess the reasonableness of the 

projection. The analytic parameters, 

when considered as a whole, should 

reflect a logically consistent future 

outlook of the electric system. Refer to 

the Incorporating RE and Demand-side 

EE Impacts into State Plan 

Demonstrations TSD of the final rule for 

further details on quantifying impacts of 

eligible RE and demand-side EE 

measures. 

The CO2 emission performance 

projection documentation must include: 


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• Geographic representation, which must 

be appropriate for capturing impacts and/or 

changes in the electric system 

• Time period of analysis, which must 

extend through 2031 

• Electricity demand forecast (MWh load 

and MW peak demand) at the state and 

regional level. If the demand forecast is not 

from NERC, an ISO or RTO, EIA, or other 

publicly available source, then the projection 

must include justification and 

documentation of underlying assumptions 

that inform the development of the demand 

forecast, such as annual economic and 

demand growth rate, population growth rate. 

• Planning reserve margins 

• Planned new electric generating capacity 

• Analytic treatment of the potential for 

building unplanned new electric generating 

capacity 

• Wholesale electricity prices 

• Fuel prices, when applicable; 

• Fuel carbon content 

• Unit-level fixed operations and 

maintenance costs, when applicable; 

• Unit-level variable operations and 

maintenance costs, when applicable; 

• Unit-level capacity 

• Unit-level heat rate 

• If applicable, EGU-specific actions in the 

state plan designed to meet the required CO2

emission performance, including their 

timeline for implementation 

• If applicable, state-enforceable measures, 

with electricity savings and renewable 

electricity generation (MWhs) expected for 

individual and collective measures, as 

applicable. Quantification of MWhs expected 

from EE and RE measures will involve 

assumptions that states must document, as 

described in the Incorporating RE and 

Demand-side EE Impacts into State Plan 

Demonstrations TSD. 

• Annual electricity generation (MWh) by 

fuel type and CO2 emission levels, for each 

affected EGU 

• ERC or emission allowance prices, when 

applicable 

The state must also provide a clear 

demonstration that the state measures 

and/or federally enforceable emission 

standards informing the projected 

achievement of the emission 

performance requirements will be 

permanent and remain in place. 

The EPA encourages participation in 

regional modeling efforts which are 

designed to allow sharing of data and 

help promote consistent approaches 

across state boundaries. A state that 

submits a single-state plan must 

consider interstate transfer of electricity 

across state boundaries, taking into 

account other states’ plan types 

reflecting the best available information 

at the time of the CO2 emission 

performance projection. Projections of 

CO2 emission performance for multistate plans and single-state plans that 

include multi-state coordination must 

either use a single (regional) electricity 

demand forecast or must document the 

use of electricity demand forecasts from 

different information sources and 

demonstrate how any inconsistencies 

between the individual electricity 

demand forecasts have been reconciled. 

(d) Additional projection 

requirements under a rate-based 

emission standards plan. For an 

emission standards plan that applies 

rate-based CO2 emission standards to 

individual affected EGUs, or to 

subcategories of affected EGUs, at a lb 

CO2/MWh rate that differs from the CO2

emission performance rates or the state’s 

rate-based CO2 goal in the emission 

guidelines, a projection of affected EGU 

CO2 emission performance is required. 

The state must demonstrate that the 

weighted average CO2 emission rate of 

affected EGUs, when weighted by 

generation (in MWh) from affected 

EGUs subject to the different rate-based 

emission standards, will be equal to or 

less than the CO2 emission performance 

rates or the state’s rate-based CO2

emission goal during the interim and 

final plan performance periods. 

The projection will involve an 

analysis of the change in generation of 

affected EGUs given the compliance 

costs and incentives under the 

application of different emission rate 

standards across affected EGUs in a 

state. It must accurately represent the 

emission standards in the plan, 

including the use of market-based 

aspects of the emission standards (if 

applicable), such as use of ERCs or 

emission allowances as compliance 

instruments. 

In addition to the elements described 

in the previous section (c), the 

projection under this plan design must 

include: 

• The assignment of federally enforceable 

emission standards for each affected EGUs; 

• A projection showing how generation is 

expected to shift between affected EGUs and 

across affected EGUs and non-affected EGUs 

over time; 

• Underlying assumptions regarding the 

availability and anticipated use of the MWh 

of electricity generation or electricity savings 

from eligible measures that can be issued 

ERCs; 

• The specific calculation (or assumption) 

of how eligible MWh of electricity generation 

or savings that can be issued ERCs are being 

used in the projection to adjust the reported 

CO2 emission rate of affected EGUs, 

consistent with the accounting methods for 

adjusting the CO2 emission rate of an affected 

EGU specified in section VIII.K.1 of the 

emission guidelines, if applicable; 

• ERC prices, if applicable; 

• If a state plan provides for the ability of 

RE resources located in states with massbased plans to be issued ERCs for use in 

adjusting the reported CO2 emission rates of 

affected EGUs, consideration in the 

projection that such resources must meet 

geographic eligibility requirements, based on 

power purchase agreements or related 

documentation, consistent with the 

requirements at section VIII.K.1 and section 

VIII.L; and 

• Any other applicable assumptions used 

in the projection. 

(e) Additional projections 

requirements for a state measures plan. 

For a state measures plan, a projection 

of affected EGU CO2 emission 

performance must demonstrate that the 

state measures, whether alone or in 

conjunction with any federally 

enforceable CO2 emission standards for 

affected EGUs, will achieve the state’s 

mass-based CO2 goals in the emission 

guidelines for the interim and final 

periods. The projection must accurately 

represent individual state-enforceable 

measures (or bundled measures) and 

timing for implementation of these state 

measures. 

A state must demonstrate that its 

state-enforceable measures, along with 

any federally enforceable CO2 emission 

standards for affected EGUs included in 

a state plan, will achieve the state massbased CO2 goal. In addition to the 

elements described in section 

VIII.D.2.a.(3).(c), the state must clearly 

document, at a minimum: 

• The assignment of federally enforceable 

emission standards for each affected EGUs, if 

applicable; and 

• the individual state measures, including 

their projected impacts over time. 

Because different types of state 

measures could have varying degrees of 

impact on reducing or avoiding CO2

emissions from affected EGUs, and 

different state measures may interact 

with one another in terms of CO2

emission reduction impacts, the method 

and tools a state uses to project CO2

emissions impacts must have the 

capability to project how the combined 

set of state-enforceable measures are 

likely to impact CO2 emissions at 

affected EGUs. If a state chooses to use 

an emission budget trading program as 

a mass-based state measure, for 

example, the state must choose an 

analytic method or tool that can account 

for and properly represent any program 

flexibilities that impact CO2 emissions 

from affected EGUs, such as use of outof-sector GHG offsets and costcontainment provisions. The state 

would show that the emissions budget 

trading program relied upon for the state 

measures plan, as well as any other state 

measures, ensure that the sum of 

emissions at all affected EGUs will be 

lower than or equal to the state’s CO2

emission goal in the time periods 

specified in these guidelines. All 

flexibilities must be clearly documented 

in the demonstration. 


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(4) Monitoring, reporting and 

recordkeeping requirements for affected 

EGUs. 

The state plan submittal must specify 

how each emission standard is 

quantifiable and verifiable by describing 

the CO2 emission monitoring, reporting 

and recordkeeping requirements for 

affected EGUs. The applicable 

monitoring, recordkeeping and 

reporting requirements for affected 

EGUs are outlined in section VIII.F. 

In the June 2014 proposal, the EPA 

proposed that states must include in 

their state plans a record retention 

requirement for affected EGUs to 

maintain records for at least 10 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report or record. Commenters 

requested clarification of the record 

retention requirements for states as 

compared to for affected EGUs and also 

requested that the EPA clarify onsite 

versus offsite record maintenance 

requirements for affected EGUs. The 

EPA is finalizing that states must 

include in their plans a record retention 

requirement for affected EGUs of not 

less than 5 years following the date of 

each compliance period, compliance 

true-up period, occurrence, 

measurement, maintenance, corrective 

action, report, or record, whichever is 

latest. Affected EGUs must maintain 

each record onsite for at least 2 years 

after the date of the occurrence of each 

record and may maintain records offsite 

and electronically for the remaining 

years. Each record must be in a form 

suitable and readily available for 

expeditious review. The EPA finds that 

these final recordkeeping requirements 

are appropriate and consistent with the 

requirements for other CAA section 

111(d) emission guidelines. 

(5) State reporting and recordkeeping 

requirements. 

A state plan submittal must contain 

the process, content and schedule for 

state reporting to the EPA on plan 

implementation and progress toward 

meeting the CO2 emission performance 

rates or state CO2 emission goal. 

The EPA requested comments on 

whether full reports containing all of the 

report elements should only be required 

every 2 years and on the appropriate 

frequency of reporting of the different 

proposed elements, considering both the 

goals of minimizing unnecessary 

burdens on states and ensuring program 

transparency and effectiveness. 

Commenters recognized that different 

reporting frequencies may be 

appropriate for different types of state 

plans. The EPA agrees with the 

commenters and is finalizing state 

reporting requirements based on the 

type of plan the state chooses to adopt 

and implement. These state reporting 

requirements and reporting periods are 

discussed in section VIII.D.2.b (for 

emission standards plan types) and 

VIII.D.2.c (for state measures plan 

types). The EPA finalizes that each state 

report is due to the EPA no later than 

the July 1 following the end of each 

reporting period. The EPA recognizes 

the multiple comments received 

recommending extending the state 

report due date from July 1 to a later 

date or to allow the states the flexibility 

to propose an alternative report 

submittal date. The EPA is not pursuing 

these recommendations due to the 

implications of the state reports’ due 

date and the trigger and schedule for 

implementation of corrective measures 

(for the emission standards approach) or 

the backstop federally enforceable 

emission standards (for the state 

measures approach). The EPA believes 

the July 1 deadline for states to submit 

reports to the EPA on plan 

implementation is feasible given that 

the information required to be included 

in the reports will be available per the 

reporting requirements for affected 

EGUs in state plans. 

In addition to the state reporting 

requirements discussed in section 

VIII.D.2.b (for emission standards 

approach) and VIII.D.2.c (for state 

measures approach) and as discussed 

below, states must include in the 

supporting material of a final state plan 

submittal a timeline with all the 

programmatic plan milestone steps the 

state will take between the time of the 

final state plan submittal and 2022 to 

ensure the plan is effective as of 2022. 

The EPA is also finalizing a requirement 

that states must submit a report to the 

EPA in 2021 that demonstrates that the 

state has met the programmatic plan 

milestone steps that the state indicated 

it would take from the submittal of the 

final plan through the end of 2020, and 

that the state is on track to implement 

the approved state plan as of January 1, 

2022. A final state plan submission 

must include a requirement for the state 

to submit this report to the EPA no later 

than July 1, 2021. This report will help 

the EPA further assist and facilitate plan 

implementation with states as part of an 

ongoing joint effort to ensure the 

necessary reductions are achieved. 

The EPA is finalizing the requirement 

that submissions related to this program 

be submitted electronically. 

Specifically, this includes negative 

declarations, state plan submittals 

(including any supporting materials that 

are part of a state plan submittal), any 

plan revisions, and all reports required 

by the state plan. The EPA is developing 

an electronic system to support this 

requirement that can be accessed at the 

EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). See section 

VIII.E.8 for additional information on 

electronic submittal requirements. 

In the June 2014 proposal, the EPA 

proposed that states must keep records, 

for a minimum of 20 years, of all plan 

components, plan requirements, plan 

supporting documentation and status of 

meeting the plan requirements, 

including records of all data submitted 

by each affected EGU used to determine 

compliance with its emission standards. 

The EPA received multiple comments 

recommending that the EPA reduce 

recordkeeping requirements due to the 

burden in expenditure of resources and 

manpower to maintain records for at 

least 20 years. Commenters 

recommended that recordkeeping 

requirements be reduced to 5 years 

consistent with emission guidelines for 

other existing sources. 

After considering the comments 

received, this final rule requires that a 

state must keep records of all plan 

components, plan requirements, 

supporting documentation, and the 

status of meeting the plan requirements 

defined in the plan for the interim plan 

period from 2022–2029 (including 

interim steps 1, 2 and 3). After 2029, 

states must keep records of all 

information relied upon in support of 

any continued demonstration that the 

final CO2 emission performance rates or 

goals are being achieved. The EPA 

agrees with comments that a 20-year 

record retention requirement could be 

unduly burdensome, and has reduced 

the length of the record retention 

requirement for the final rule. During 

the interim period, states must keep 

records for 10 years from the date the 

record is used to determine compliance 

with an emission standard, plan 

requirement, CO2 emission performance 

rate or CO2 emission goal. During the 

final period, states must keep records 

for 5 years from the date the record is 

used to determine compliance with an 

emission standard, plan requirement, 

CO2 emission performance rate or CO2

emissions goal. All records must be in 

a form suitable and readily available for 

expeditious review. States must also 

keep records of all data submitted by 

each affected EGU that was used to 

determine compliance with each 

affected EGU’s emission standard, and 

such data must meet the requirements of 

the emission guidelines, except for any 

information that is submitted to the EPA 

electronically pursuant to requirements 

in 40 CFR part 75. If the state is 

adopting and implementing the state 

measures approach, the state must also 


tkelley on DSK3SPTVN1PROD with BOOK 2
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822While we specifically encourage state 

environmental agencies and utility regulators to 

consult here, we note that, under CAA programs, 

state agencies have a history of consultation with 

one another as appropriate. 

823USGCRP 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. 

maintain records of all data regarding 

implementation of each state measure 

and all data used to demonstrate 

achievement of the mass CO2 emission 

goal and such data must meet the 

requirements of the emission guidelines. 

The EPA finds that these final 

recordkeeping requirements balance the 

need to maintain records while reducing 

the strain on state resources. 

(6) Public participation and 

certification of hearing on state plan. 

A robust and meaningful public 

participation process during state plan 

development is critical. For the final 

plan submittal, states must 

meaningfully engage with members of 

the public, including vulnerable 

communities, during the plan 

development process. This section 

describes how the EPA will evaluate a 

state plan for compliance with the 

minimum required elements for public 

participation provided in the existing 

implementing regulations as well as 

recommendations for other steps the 

state can take to assure robust and 

inclusive public participation. 

The existing implementing 

regulations regarding public 

participation requirements are in 40 

CFR 60.23(c)–(f). Per the implementing 

regulations, states must conduct a 

public hearing on a final state plan 

before such plan is adopted and 

submitted. State plan development can 

be enhanced by tapping the expertise 

and program experience of several state 

government agencies. The EPA 

encourages states to include utility 

regulators (e.g. the PUCs) and state 

energy offices as appropriate early on 

and throughout in the development of 

the state plan.822 The EPA notes that 

utility regulators and state energy offices 

have the opportunity during the public 

participation processes required for 

state plans to provide input as well. The 

EPA also encourages states to conduct 

outreach meetings (that could include 

public hearings or meetings) with 

vulnerable communities on its initial 

submittal before the plan is submitted. 

In its final plan submittal, a state must 

provide certification that the state made 

the plan submittal available to the 

public and gave reasonable notice and 

opportunity for public comment on the 

state plan submittal. The state must 

demonstrate that the public hearing on 

the state plan was held only after 

reasonable notice, which will be 

considered to include, at least 30 days 

prior to the date of such hearing, notice 

given to the public by prominent 

advertisement announcing the date(s), 

time(s) and place(s) of such hearing(s). 

For each hearing held, a state plan 

submittal must include in the 

supporting documentation the list of 

witnesses and their organizational 

affiliations, if any, appearing at the 

hearing, and a brief written summary of 

each presentation or written submission 

pursuant to the requirements of the 

implementing regulations at 40 CFR 

60.23. Additionally, the EPA 

recommends that states work with local 

municipalities, community-based 

organizations and the press to advertise 

their state public hearing(s). The EPA 

also encourages states to provide 

background information about their 

proposed final state plan or their initial 

submittal in the appropriate languages 

in advance of their public hearing and 

at their public hearing. Additionally, the 

EPA recommends that states provide 

translators and other resources at their 

public hearings, to ensure that all 

members of the public can provide oral 

feedback. 

As previously discussed in this rule, 

recent studies also find that certain 

communities, including low-income 

communities and some communities of 

color (more specifically, populations 

defined jointly by ethnic/racial 

characteristics and geographic location) 

are disproportionately affected by 

certain climate change related 

impacts.823 Also as discussed in this 

rule, effects from this rule can be 

anticipated to affect vulnerable 

communities in various ways. Because 

certain communities have a potential 

likelihood to be impacted by state plans, 

the EPA believes that the existing public 

participation requirements under 40 

CFR 60.23 are effectuated for the 

purposes of this final rule by states 

engaging in meaningful, active ways 

with such communities. 

In addition, certain communities 

whose economies are significantly 

dependent on coal, or whose economies 

may be affected by ongoing changes in 

the utility power and related sectors, 

may be particularly concerned about the 

final rule. The EPA encourages states to 

make an effort to provide background 

information about their proposed initial 

submittal and final state plans to these 

communities in advance of their public 

hearing. In particular, the EPA 

encourages states to engage with 

workers and their representatives in the 

utility and related sectors, including the 

EE sector. 

The EPA notes that meaningful public 

involvement goes beyond the holding of 

a public hearing. The EPA envisions 

meaningful engagement to include 

outreach to vulnerable communities, 

sharing information and soliciting input 

on state plan development and on any 

accompanying assessments, such as 

those described in section IX. The 

agency uses the terms ‘‘vulnerable’’ and 

‘‘overburdened’’ in referring to lowincome communities, communities of 

color, and indigenous populations that 

are most affected by, and least resilient 

to, the impacts of climate change, and 

are central to our community and 

environmental justice considerations. In 

section VIII.E, the EPA provides states 

with examples of resources on how they 

can engage with vulnerable 

communities in a meaningful way. With 

respect specifically to ensuring 

meaningful community involvement in 

their public hearing(s), however, the 

EPA recommends that states have both 

a Web site and toll-free number that all 

stakeholders, including overburdened 

communities, labor unions, and others 

can access to get more information 

regarding the upcoming hearing(s) and 

to get their questions related to 

upcoming hearings answered. 

Furthermore, the EPA recommends that 

states work with their local government 

partners to help them in reaching out to 

all stakeholders, including vulnerable 

communities, about the upcoming 

public hearing(s). 

(7) Supporting documentation. 

The state plan submittal must provide 

supporting material and technical 

documentation related to applicable 

components of the plan submittal. 

(a) Legal authority. 

In its submittal, a state must 

adequately demonstrate that it has the 

legal authority (regulations/legislation) 

and funding to implement and enforce 

each component of the state plan 

submittal, including federally 

enforceable emission standards for 

affected EGUs and state measures. A 

state can make such a 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 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64849 

824 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). 

the necessary authority to enter into a 

multi-state agreement. 

(b) Technical documentation. 

As applicable, the state submittal 

must include materials necessary to 

support the EPA’s evaluation of the 

submittal including analytical materials 

used in the calculation of interim goal 

steps (if applicable), analytical materials 

used in the multi-state goal calculation 

(if multi-state plan), analytical materials 

used in projecting CO2 emission 

performance that will be achieved 

through the plan, relevant 

implementation materials and any 

additional technical requirements and 

guidance the state proposes to use to 

implement elements of the plan. 

(c) Programmatic plan milestones and 

timeline. 

As part of the state plan supporting 

documentation, the state must include 

in its submittal a timeline with all the 

programmatic plan milestone steps the 

state will take between the time of the 

state plan submittal and 2022 to ensure 

the plan is effective as of January 1, 

2022. The programmatic plan 

milestones and timeline should be 

appropriate to the overall state plan 

approach included in the state plan 

submittal. 

(d) Reliability. 

As discussed in more detail in section 

VIII.G.2, each state must demonstrate as 

part of its state plan submission that it 

has considered reliability issues while 

developing its plan. 

b. Additional components required for 

the emission standards plan type. The 

EPA is finalizing requirements that a 

final plan submittal using the emission 

standards plan type must contain the 

following components, in addition to 

the components discussed in the 

preceding section VIII.D.2.a. 

(1) Identification of interim period 

emission performance rates or state goal 

(for 2022–2029), interim step 

performance rates or interim state goals 

(2022–2024; 2025–2027; 2028–2029) and 

final emission performance rates or 

state goal (2030 and beyond). 

The state plan submittal must indicate 

whether the plan is designed to meet the 

CO2 emission performance rates or the 

state rate-based or mass-based CO2

emission goal. As noted in the emission 

guidelines, the EPA is finalizing CO2

emission performance rates for fossil 

fuel-fired steam generating units and for 

stationary combustion turbines. The 

EPA has translated the source categoryspecific CO2 emission performance rates 

into equivalent state-level rate-based 

and mass-based CO2 goals in order to 

maximize the range of choices that 

states will have in developing their 

plans. The state may choose to develop 

a state plan that meets the CO2

performance rates for the two 

subcategories of affected EGUs or 

develop a plan that adopts either the 

rate-based or the mass-based state CO2

emission goal provided in the emission 

guidelines. 

Each state plan submittal must 

identify the emission performance rates 

or rate-based or mass-based CO2

emission goal that must be achieved 

through the plan (expressed in numeric 

values, including the units of 

measurement, such as pounds of CO2

per net MWh of useful energy output or 

tons of CO2). The plan submittal must 

identify the CO2 interim period 

performance rates or state goal (for 

2022–2029), interim step performance 

rates or state goals (interim step 

performance rates or state goal 1 for 

2022–2024; interim step performance 

rates or state goal 2 for 2025–2027; 

interim step performance rates or state 

goal 3 for 2028–2029) and final CO2

emission performance rates or state goal 

of 2030 and beyond. 

The EPA has finalized an interim 

performance rates or state goal for the 

interim period of 2022–2029 and a final 

performance rates or state goal to be met 

by 2030. For the interim period, the EPA 

has also finalized three interim step 

performance rates or state goals: interim 

step 1 performance rates or state goal for 

2022–2024, interim step 2 performance 

rates or state goal for 2025–2027 and 

interim step 3 performance rates or state 

goal for 2028–2029.824 States are free to 

establish different interim step 

performance rates or interim step state 

goals than those the EPA has specified 

in this final rule. If states choose to 

determine their own interim step 

performance rates or state goals, the 

state must demonstrate that the plan 

will still meet the interim performance 

rates or state goal for 2022–2029 

finalized in the emission guidelines and 

the plan submittal must include in its 

supporting documentation a description 

of the analytic process, tools, methods, 

and assumptions used to make this 

demonstration. 

For states participating in a multistate plan with a joint goal (for interim 

and final periods), the individual state 

goals in the emission guidelines would 

be replaced with an equivalent multistate goal for each period (interim and 

final). For a rate-based multi-state plan 

this would be a weighted average ratebased 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 multi-state plan, the joint 

goal would be a sum of the individual 

mass-based goals of the participating 

states, in tons of CO2. The plan 

submittal must include in its supporting 

documentation a description of the 

analytic process, tools, methods, and 

assumptions used to calculate the joint 

multi-state goal. 

(2) Identification of federally 

enforceable emission standards for 

affected EGUs. 

The state plan submittal for an 

emission standards plan type must 

include federally enforceable emission 

standards that apply to affected EGUs. 

The emission standards must meet the 

requirement of component (3) of this 

section, ‘‘Demonstrations that each 

emission standard is quantifiable, nonduplicative, 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 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 state 

plan must include requirements 

addressing the issuance, tracking and 

use for compliance of ERCs consistent 

with the requirements in the emission 

guidelines. These requirements are 

discussed in sections VIII.K.1–2. The 

state plan must also demonstrate that 

the appropriate ERC tracking 

infrastructure that meets the 


tkelley on DSK3SPTVN1PROD with BOOK 2
64850 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

825A CO2 continuous emissions monitoring 

system (CEMS) is the most technically reliable 

method of emission measurement for EGUs. A 

CEMS provides a measurement method that is 

performance based rather than equipment specific 

and is verified based on NIST traceable standards. 

A CEMS provides a continuous measurement 

stream that can account for variability in the fuels 

and the combustion process. Reference methods 

have been developed to ensure that all CEMS meet 

the same performance criteria, which helps to 

ensure a level playing field and consistent, accurate 

data. 

826For example, an ERC that is issued by a state 

under its rate-based emission standards may be 

used only once by an affected EGU to adjust its 

reported CO2 emission rate when demonstrating 

compliance with the emission standards. However, 

an ERC issued in one state could be used by an 

affected EGU to demonstrate compliance with its 

emission standard in another state, where states are 

collaborating in the implementation of their 

individual emission trading programs through 

interstate transfer of ERCs, or participating in a 

multi-state plan with a rate-based emission trading 

program. These coordinated multi-state approaches 

are addressed in sections VIII.C.5, VIII.J.3, and 

VIII.K.4. 

827The EPA guidance on enforceability includes: 

(1) September 23, 1987, memorandum and 

accompanying implementing guidance, ‘‘Review of 

State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,’’ (2) August 5, 

2004, ‘‘Guidance on SIP Credits for Emission 

Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures,’’ and (3) July 2012 

‘‘Roadmap for Incorporating Energy Efficiency/ 

Renewable Energy Policies and Programs into State 

and Tribal Implementation Plans, Appendix F.’’ 

828See prior footnote. 

829State Plan Considerations technical support 

document for the Clean Power Plan Proposed Rule: 

http://www2.epa.gov/carbon-pollution-standards/ 

clean-power-plan-proposed-rule-state-planconsiderations. 

requirements of the emission guidelines 

will be in place to administer the state 

plan requirements regarding ERCs and 

document the functionality of the 

tracking system. State plan requirements 

must include provisions to ensure that 

ERCs are properly tracked from issuance 

to submission for compliance. The state 

plan must also demonstrate that the 

MWh for which ERCs are issued are 

properly quantified and verified, 

through plan requirements for EM&V 

and verification that meet the 

requirements in the emission 

guidelines. EM&V requirements are 

discussed in section VIII.K.3. Rate-based 

emission standards must also include 

monitoring, reporting, and 

recordkeeping requirements for CO2

emissions and useful energy output for 

affected EGUs; and related compliance 

demonstration requirements and 

mechanisms. These requirements are 

discussed in more detail in sections 

VIII.F and VIII.K. 

For state plans using a mass-based 

emission trading program approach, the 

state plan must include implementation 

requirements that specify the emission 

budget and related compliance 

requirements and mechanisms. These 

requirements must include: CO2

emission monitoring, reporting, and 

recordkeeping requirements for affected 

EGUs; provisions for state allocation of 

allowances; provisions for tracking of 

allowances, from issuance through 

submission for compliance; and the 

process for affected EGUs to 

demonstrate compliance (allowance 

‘‘true-up’’ with reported CO2 emissions). 

(3) Demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable and 

enforceable. 

The plan submittal must demonstrate 

that each emission standard is 

quantifiable, non-duplicative, 

permanent, verifiable and enforceable 

with respect to an affected EGU, as 

outlined below. 

An emission standard is quantifiable 

if it can be reliably measured, using 

technically sound methods, in a manner 

that can be replicated.825

An emission standard is nonduplicative with respect to an affected 

EGU if it is not already incorporated in 

another state plan, except in instances 

where incorporated as part of a multistate plan. An example of a duplicative 

emission standard would occur, for 

example, where a quantified and 

verified MWh from a wind turbine 

could be applied in more than one 

state’s CAA section 111(d) plan to adjust 

the reported CO2 emission rate of an 

affected EGU (e.g., through issuance and 

use of an ERC), except in the case of a 

multi-state plan where CO2 emission 

performance is demonstrated jointly for 

all affected EGUs subject to the multistate plan or where states are 

implementing coordinated individual 

plans that allow for the interstate 

transfer of ERCs.826 This does not mean 

that measures used to comply with an 

emission standard cannot also be used 

for other purposes. For example, a MWh 

of electric generation from a wind 

turbine could be used by an electric 

distribution utility to comply with state 

RPS requirements and also be used by 

an affected EGU to comply with 

emission standard requirements under a 

state plan. Another example is when 

actions taken pursuant to CAA section 

111(d) requirements can satisfy other 

CAA program requirements (e.g., 

Regional Haze requirements, MATS). 

An emission standard is permanent if 

the emission standard must be met for 

each applicable compliance period. 

An emission standard is verifiable if 

adequate monitoring, recordkeeping and 

reporting requirements are in place to 

enable the state and the Administrator 

to independently evaluate, measure, and 

verify compliance with it. 

An emission standard is enforceable 

if: (1) It represents a technically accurate 

limitation or requirement and the time 

period for the limitation or requirement 

is specified; (2) compliance 

requirements are clearly defined; (3) the 

entities responsible for compliance and 

liable for violations can be identified; 

and (4) each compliance activity or 

measure is enforceable as a practical 

matter in accordance with EPA 

guidance on practical enforceability,827

and the Administrator, the state, and 

third parties maintain the ability to 

enforce against affected EGUs for 

violations and secure appropriate 

corrective actions, in the case of the 

Administrator pursuant to CAA sections 

113(a)–(h), in the case of a state, 

pursuant to its state plan, state law or 

CAA section 304, as applicable, and in 

the case of third parties, pursuant to 

CAA section 304. 

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.828 These guidance 

documents serve as the foundation for 

the types of monitoring, reporting, and 

emission standards that the EPA has 

found can be, as a practical matter, 

enforced. 

In the proposed regulatory text 

describing the enforcing measures that 

states must include in state plans, the 

EPA inadvertently excluded a required 

demonstration that states and other 

third parties can enforce against affected 

EGUs for violations of an emission 

standard included in a state plan via 

civil action pursuant to CAA section 

304. Commenters noted the EPA’s intent 

to require this demonstration based on 

statements in both the proposal 

preamble text and ‘‘State Plan 

Considerations’’ TSD 829 and based on 

the requirements of CAA section 304. 

We are finalizing a requirement for a 

demonstration that states and other 

third parties can enforce against affected 

EGUs for violations of an emission 

standard included in a state plan via 

civil action as part of the required plan 

component demonstrating 

enforceability. We are finalizing this 

requirement as a logical outgrowth of 

proposal preamble text, the proposal 

preamble citation to existing 

enforceability guidance documents that 

discuss this requirement, comments 

received, and the clear statutory 

foundation. 

(4) State reporting requirements. 

After consideration of the comments 

received regarding state reporting 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64851 

830 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). 

requirements, the EPA is finalizing for 

state plans using the emission standards 

approach that a state report is due to the 

EPA no later than the July 1 following 

the end of each reporting period. Within 

the interim period (2022–2029) the EPA 

is finalizing the following interim 

reporting periods: Interim step 1 covers 

the three calendar years 2022–2024, 

interim step 2 covers the three calendar 

years 2025–2027, and interim step 3 

covers the two calendar years 2028– 

2029. A biennial state report is required 

starting in 2030 and beyond covering 

the two calendar years of each reporting 

period. This final reporting schedule 

reduces the reporting frequency for 

states implementing the emission 

standards approach and is responsive to 

comments received that different 

reporting frequencies may be 

appropriate for different type of state 

plans. The EPA believes that because of 

the federally enforceable emission 

standards that apply to affected EGUs 

and their corresponding monitoring, 

reporting and recordkeeping 

requirements under the emission 

standards plan type, a lesser frequency 

of reporting by the state is warranted. 

The state must include in each report 

to the EPA the status of implementation 

of emission standards for affected EGUs 

under the state plan, including current 

aggregate and individual CO2 emission 

performance by affected EGUs during 

the reporting period. The state report 

must include compliance 

demonstrations for affected EGUs and 

identify whether affected EGUs are on 

schedule to meet the applicable CO2

emission performance rate or emission 

goal during the performance periods 

and compliance periods, as specified in 

the state plan. For rate-based emission 

trading programs, the report must also 

include for EPA review the state’s 

review of the administration of their 

state rate-based emission trading 

program, as discussed in section 

VIII.K.2.g. 

As discussed in more detail in section 

VIII.F, the state must include an interim 

performance check in the report 

submitted after each of the first two 

interim step periods. The interim 

performance check will compare the 

CO2 emission performance level 

identified in the state plan for the 

applicable interim step period with the 

actual CO2 emission performance 

achieved by affected EGUs during the 

period. In the report due to the EPA on 

July 1, 2030, the state must include a 

comparison of the actual CO2 emission 

performance achieved by affected EGUs 

for the interim period (2022–2029) with 

the interim CO2 emission performance 

rates or state rate-based or mass-based 

CO2 interim goal, as applicable. The 

report due on July 1, 2030, must also 

include the actual CO2 emission 

performance achieved by affected EGUs 

during the interim step 3 period (2028– 

2029). Starting in 2032, the biennial 

state report must include a final 

performance check to demonstrate that 

the affected EGUs continue to meet the 

final CO2 emission performance rates or 

state rate-based or mass-based CO2 goal. 

For state plans that use the emission 

standards approach and are subject to 

the corrective measures provisions in 

the emission guidelines, if actual CO2

emission performance (i.e., the 

emissions or emission rate) of affected 

EGUs exceeds the specified level of CO2

emission performance in the state plan 

by 10 percent or more during the 

interim step 1 or step 2 reporting 

periods, the state report must include a 

notification to the EPA that corrective 

measures have been triggered. The same 

notification is required if actual CO2

emission performance fails to meet the 

specified level of emission performance 

in the state plan for the 8-year interim 

performance period or any final plan 

reporting period. Corrective measures 

are discussed in detail in section VIII.F. 

c. Additional components required for 

the state measures approach. 

The EPA is finalizing requirements 

that a final plan submittal using the 

state measures approach must contain 

the following components, in addition 

to the components discussed in section 

VIII.D.2.a. We note again that states 

choosing the state measures plan type 

must use a mass-based state goal for the 

state measures and any emission 

standards on the affected EGUs prior to 

the triggering of the backstop. 

(1) Identification of interim state mass 

goal (for 2022–2029), interim step state 

mass goals (2022–2024; 2025–2027; 

2028–2029) and final state mass goal 

(2030 and beyond). 

The state plan submittal must identify 

the mass-based CO2 emission goal that 

must be achieved through the plan 

(expressed in tons of CO2). The plan 

submittal must identify the state CO2

interim period goal (for 2022–2029), 

interim step goals (interim step goal 1 

for 2022–2024; interim step goal 2 for 

2025–2027; interim step goal 3 for 

2028–2029) and final CO2 emission goal 

of 2030 and beyond. 

For each state, the EPA has finalized 

an interim goal for the interim period of 

2022–2029 and a final goal to be met by 

2030. For the interim period, the EPA 

has also finalized three interim step 

goals: Interim step 1 goal for 2022–2024, 

interim step 2 goal for 2025–2027 and 

interim step 3 goal for 2028–2029.830

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 multistate plan with a joint goal (for interim 

and final periods), the individual state 

goals in the emission guidelines would 

be replaced with an equivalent multistate goal for each period (interim and 

final). The joint goal would be a sum of 

the individual mass-based goals of the 

participating states, in tons of CO2. The 

plan submittal must include in its 

supporting documentation a description 

of the analytic process, tools, methods, 

and assumptions used to calculate the 

joint multi-state goal. 

(2) Identification of federally 

enforceable emission standards for 

affected EGUs (if applicable). 

If applicable, the state plan submittal 

must include any federally enforceable 

CO2 emission standards that apply to 

affected EGUs, and demonstrate that 

those emission standards meet the 

requirements that apply in the context 

of an emission standards approach, 

discussed in the preceding section 

VIII.D.2.b. Specifically, the state plan 

submittal must demonstrate that each 

federally enforceable emission standard 

is quantifiable, non-duplicative, 

permanent verifiable, and enforceable. If 

a state measures plan type includes CO2

emission standards that apply to 

affected EGUs, these emission standards 

must be federally enforceable. 

(3) Identification of backstop of 

federally enforceable emission 

standards. 

A state measures plan must include a 

backstop of federally enforceable 

emission standards for affected EGUs 

that fully achieve the interim and final 

CO2 emission performance rates or the 

state’s interim and final CO2 emission 

goal if the state plan fails to achieve the 

intended level of CO2 emission 

performance. The backstop emission 

standards could be based on the 

finalized model rule that the EPA is 

proposing in a separate action. For the 

federally enforceable backstop, the state 

plan submittal must identify the 


tkelley on DSK3SPTVN1PROD with BOOK 2
64852 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

831As explained in section VIII.C.3.b, state plans 

subject to the backstop requirement must require 

the backstop to take effect if actual CO2 emission 

performance by affected EGUs fails to meet the level 

of emission performance specified in the plan over 

the 8-year interim performance period (2022–2029), 

or for any 2-year final goal performance period. The 

plan also must require the backstop to take effect 

if actual emission performance is deficient by 10 

percent or more relative to the performance levels 

that the state has chosen to specify in its plan for 

the interim step 1 period (2022–2024) or the interim 

step 2 period (2025–2027). 

832Under the state measures approach, state 

measures are enforceable only per applicable state 

law. 

federally enforceable emission 

standards for affected EGUs, 

demonstrate that those emission 

standards meet the requirements that 

apply in the context of an emission 

standards approach, discussed in the 

preceding section, identify a schedule 

and trigger for implementation of the 

backstop that is consistent with the 

requirements in the emission guidelines 

as discussed in section VIII.C.3.b and 

identify all necessary state 

administrative and technical procedures 

for implementing the backstop (e.g. how 

and when the state would notify 

affected EGUs that the backstop has 

been triggered). Aspects of the backstop 

are discussed in detail in section 

VIII.C.3.b. 

(4) Identification of state measures. 

A state adopting a state measures plan 

type must provide as a part of the 

supporting documentation of its plan 

submittal, a description of all the state 

enforceable measures the state will rely 

upon to achieve the requisite state massbased goal, the applicable state laws or 

regulations related to such measures, 

and identification of parties or entities 

implementing or complying with such 

state measures. The state must also 

include in its supporting documentation 

the schedule and milestones for the 

implementation of the state measures, 

showing that the measures are expected 

to achieve the mass-based CO2 emission 

goal for the interim period (including 

the interim step periods) and meet the 

final goal by 2030. A state measures 

plan submittal that relies upon state 

measures that include RE and demandside EE programs and projects must also 

demonstrate in its supporting 

documentation that the minimum 

EM&V requirements in the emission 

guidelines apply to those programs and 

projects as a matter of state law. 

(5) State reporting requirements. 

After consideration of the comments 

received regarding state reporting 

requirements, the EPA is requiring in 

this final rule for states using the state 

measures approach that an annual state 

report is due to the EPA no later than 

July 1 following the end of each 

calendar year during the interim period. 

This annual state report must include 

the status of implementation of federally 

enforceable emission standards (if 

applicable) and state measures, and 

must include a report of the periodic 

programmatic state measures milestones 

to show progress in program 

implementation. The programmatic 

state measures milestones with specific 

dates for achievement should be 

appropriate to the state measures 

described in the supporting 

documentation of the state plan 

submittal. The EPA believes that annual 

state reporting is appropriate for state 

measures approach due to the flexibility 

inherent to the approach described in 

section VIII.C.3 including the potential 

use by the state of a wider variety of 

state measures, responsible parties, etc. 

This reporting frequency will also 

increase the degree of certainty on plan 

performance for states pursuing the state 

measures approach. 

As discussed in section VIII.F, for 

states using the state measures 

approach, the EPA is finalizing that at 

the end of the first two interim step 

periods, the state must also include in 

their annual report to the EPA the 

corresponding emission performance 

checks. The interim performance checks 

will compare the CO2 emission 

performance level identified in the state 

plan for the applicable interim step 

period versus the actual CO2 emission 

performance achieved by the aggregate 

of affected EGUs. In the report 

submitted to the EPA on July 1, 2030, 

the state must also report the actual CO2

performance check for the interim 

period (2022–2029) with the interim 

mass-based CO2 goal, as well as the 

actual CO2 emission performance 

achieved by affected EGUs during the 

interim step 3 period (2028–2029). 

Beginning with the final period, the 

state must submit biennial reports no 

later than July 1 after the end of each 

reporting period that includes an actual 

performance check to demonstrate that 

the state continues to meet the final 

state CO2 goal. 

If, at the time of the state report to the 

EPA, the state has not met the 

programmatic state measures milestones 

for the reporting period, or the 

performance check shows that the 

actual CO2 emission performance of 

affected EGUs warrants implementation 

of backstop requirements,831 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 

affected EGUs must be effective within 

18 months of the deadline for the state 

reporting to the EPA on plan 

implementation and progress toward 

meeting the emission performance rates 

or mass-based or rate-based state CO2

emission goal. For example, if a state 

report due on July 1, 2025, shows that 

actual CO2 emission performance of 

affected EGUs is deficient by 10 percent 

or more relative to the specified level of 

emission performance for 2022–2024 in 

the state plan, the backstop federally 

enforceable emission standards for 

affected EGUs must be effective as of 

January 1, 2027. 

(6) Supporting documentation. 

(a) Demonstration that each state 

measure is quantifiable, 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 measures that are not 

federally enforceable emission 

standards, and describe how each state 

measure is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable with respect to an affected 

entity. 

A state measure is quantifiable if it 

can be reliably measured, using 

technically sound methods, in a manner 

that can be replicated. 

A state measure is non-duplicative 

with respect to an affected entity if it is 

not already incorporated as a state 

measure or an emission standard in 

another state plan or state plan 

supporting material, except in instances 

where incorporated in another state as 

part of a multi-state plan. This does not 

mean that measures in a state measure 

cannot also be used for other purposes. 

For example actions taken pursuant to 

CAA section 111(d) requirements can 

satisfy other CAA program requirements 

(e.g., Regional Haze requirements, 

MATS) and state requirements (e.g., 

RPS). 

A state measure is permanent if the 

state measure must be met for each 

applicable compliance period. 

A state measure is verifiable if 

adequate monitoring, recordkeeping and 

reporting requirements are in place to 

enable the state to independently 

evaluate, measure and verify 

compliance with it. 

A state measure is enforceable 832 if: 

(1) It represents a technically accurate 

limitation or requirement and the time 

period for the limitation or requirement 


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833The 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. 

834On 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. 

is specified; (2) compliance 

requirements are clearly defined; (3) the 

affected entities responsible for 

compliance and liable for violations can 

be identified; and (4) each compliance 

activity or measure is practically 

enforceable in accordance with EPA 

guidance on practical enforceability,833

and the state maintains the ability to 

enforce against affected EGUs for 

violations and secure appropriate 

corrective actions pursuant to its plan or 

state law. 

The EPA will disapprove a state plan 

if the documentation is not sufficient for 

the EPA to be able to determine whether 

the state measures are expected to yield 

CO2 emission reductions sufficient to 

result in the necessary CO2 emission 

performance from affected EGUs for the 

mass-based 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 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 fundamental 

nature in the section 110 context.834

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 

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 

legal authority, we are not dictating 

which state agencies or officials must 

specifically have the necessary legal 

authority; that is entirely up to the state 

so long as the fundamental requirement 

to have adequate legal authority to 

implement and enforce the plan is met. 

In addition, the EPA has already 

determined in the 1975 implementing 

regulations that certain components, 

such as monitoring, recordkeeping, and 

reporting, are necessary for 

implementation and enforcement of 

section 111(d) standards of 

performance. 40 FR 53340, 53348/1 

(Nov. 17, 1975). Thus, EPA’s position 

here is hardly novel. The EPA notes in 

discussing the implementing 

regulations, nothing in this final rule 

reopens provisions or issues that were 

previously decided in the original 

promulgation of the regulations unless 

otherwise explicitly reopened for this 

rule. 

(2) Legal considerations with changes 

to affected EGUs. 

In the proposed rulemaking, the EPA 

proposed the interpretation that if an 

existing source is subject to a section 

111(d) state plan, and then undertakes 

a modification or reconstruction, the 

source remains subject to the state plan, 

while also becoming subject to the 

modification or reconstruction 


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835 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. 

requirements. 79 FR 34830, 34903–4. 

The EPA is not finalizing a position on 

this issue in this final rule, and is reproposing and taking comment on this 

issue through the federal plan 

rulemaking being proposed 

concurrently with this action. The 

EPA’s deferral of action on this issue 

does not impact states’ and affected 

EGUs’ pending obligations under this 

final rule relating to plan submission 

deadlines, as this issue concerns 

potential obligations or impacts after an 

existing source is subject to the 

requirements of a state plan. The EPA 

will propose and finalize its position on 

this issue through the federal plan 

rulemaking, which will be well in 

advance of the plan performance period 

beginning in 2022, at which point state 

plan obligations on existing sources are 

effectuated. 

(3) Legal considerations regarding 

design, equipment, work practice or 

operational standards. 

In the proposal, the EPA asked for 

comment on three approaches to 

inclusion of design, equipment, work 

practice and operational standards in 

section 111(d) plans. 79 FR 34830, 

34926/3 (June 18, 2014). Under the first 

approach, states would be precluded 

from including these standards in 

section 111(d) plans unless the design, 

equipment, work practice or operational 

standard could be understood as a 

‘‘standard of performance’’ or could be 

understood to ‘‘provide for 

implementation and enforcement’’ of 

standards of performance. We also 

asked, for the first approach, whether it 

was even possible, given the statutory 

language of 111(h), to consider a design, 

equipment, work practice or operational 

standard as a ‘‘standard of 

performance.’’ Under the second 

approach, states could include design, 

equipment, work practice or operational 

standards in the event that it could be 

shown a ‘‘standard of performance’’ was 

not feasible, as set out in section 111(h). 

Under the third approach, a state could 

include design, equipment, work 

practice and operational standards in a 

111(d) plan without any constraints. We 

also asked whether, if there was legal 

uncertainty as to the status of these 

standards, the EPA should authorize 

states to include them in their 111(d) 

plans with the understanding that if the 

EPA’s authorization were invalidated by 

a court, states would have to revise their 

plans accordingly. 

The EPA is finalizing the first 

approach. Specifically, a state’s 

standards of performance (in other 

words, either the federally enforceable 

backstop under the state measures 

approach or the emission standards 

under the emission standards approach) 

cannot consist of (in whole or part) 

design, equipment, work practice or 

operational standards. A state may 

include such standards in a 111(d) plan 

in order to implement the standards of 

performance. For example, a state taking 

a mass-based approach may include in 

its 111(d) plan a limit on hours of 

operation on a particular affected EGU, 

but that operational standard itself 

cannot substitute for a mass-based 

emission standard on the affected 

EGU.835

This follows from the statute. First, 

section 111(h)(1) authorizes the 

Administrator, when it is not feasible 

for certain reasons (specified in 

111(h)(2)) to prescribe or enforce a 

standard of performance, to instead 

promulgate a design, equipment, work 

practice or operational standard. If a 

standard of performance could include 

design, equipment, work practice or 

operational standards, such authority 

would be unnecessary. Second, 

111(h)(5) states that design, equipment, 

work practice or operational standards 

‘‘described in’’ 111(h) shall be treated as 

standards of performance for the 

purposes of the CAA. This creates a 

strong inference that standards of 

performance otherwise should not 

include design, equipment, work 

practice, or operational standards. 

Finally, the general definition of 

‘‘standard of performance’’ in section 

302(l) is similar to the definition of 

‘‘emission limitation’’ (or ‘‘emission 

standard’’) in section 302(k), with the 

exception that the definition of 

‘‘emission limitation’’ explicitly 

includes design, equipment, work 

practice and operational standards, but 

the definition of ‘‘standard of 

performance’’ omits them. Thus, as with 

our discussion of the term ‘‘standard of 

performance’’ above in VIII.C.6.b, even 

if the general definition of ‘‘standard of 

performance’’ in 302(l) applies to 

111(d), the omission of design, 

equipment, work practice, and 

operational standards in 302(l) confirms 

our interpretation that they cannot be a 

111 ‘‘standard of performance’’ (except 

under the limited circumstances in 

111(h)). We conclude that it is 

reasonable, and perhaps compelled, to 

interpret the term ‘‘standards of 

performance’’ in 111(d) to not include 

design, equipment, work practice and 

operational standards. 

However, section 111(d) requires 

plans to ‘‘provide for implementation 

and enforcement of [the] standards of 

performance.’’ This language does not 

explicitly prohibit a plan from including 

design, equipment, work practice and 

operational standards, and allows for 

them to be included so long as they are 

understood to provide for 

implementation of the standards of 

performance. If they are included, the 

111(d) plan must still be ‘‘satisfactory’’ 

in other respects, in particular in 

establishing standards of performance 

that are not in whole or in part design, 

equipment, work practice, and 

operational standards. 

(4) Legal basis for engagement with 

communities. 

As previously discussed, section 

111(d)(1) requires the EPA to 

promulgate procedures ‘‘similar’’ to 

those in section 110 under which states 

adopt and submit 111(d) plans. Section 

110(a)(1) requires states to adopt and 

submit implementation plans ‘‘after 

reasonable notice and public hearings.’’ 

The implementing regulations under 40 

CFR 60.27 reflect similar public 

participation requirements with respect 

to section 111(d) state plans. The EPA 

is sensitive to the legal importance of 

adequate public participation in the 

state plan process, including public 

participation by affected communities. 

As previously discussed in this rule, 

recent studies also find that certain 

communities, including low-income 

communities and some communities of 

color, are disproportionately affected by 

certain climate change-related impacts. 

Because certain communities have a 

potential likelihood to be impacted by 

state plans for this rule, the EPA 

believes that the existing public 

participation requirements under 40 

CFR 60.23 are effectuated for the 

purposes of this final rule by states 

engaging in meaningful, active ways 

with such communities. By requiring 

states to demonstrate how they have 

meaningfully engaged with vulnerable 

communities potentially impacted by 

state plans as part of the state plan 

development process, states meeting 

this requirement will satisfy the 

applicable statutory and regulatory 

requirements regarding public 

participation. 

3. Components of the Federally 

Approved State Plan 

In this action the EPA finalizes that, 

to be fully approved, a state plan 

submittal must meet the criteria and 

include the required components 

described above. The EPA will propose 

and take final action on each state plan 

submittal in the Federal Register and 

provide an opportunity for notice and 

comment. When a state plan submittal 


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836 40 CFR 60.23(a)(1). 

837Based on comments received, we understand 

that the Northeast and Mid-Atlantic states that 

participate in RGGI may be in this position. 

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 

September 6, 2016, with the option of 

an extension to submit final state plans 

by September 6, 2018, which is 3 years 

after finalization of this rule. The 

compelling nature of the climate change 

challenge, and the need to begin 

promptly what will be a lengthy effort 

to implement the requirements of these 

guidelines, warrant this schedule. The 

EPA also believes, for reasons further 

described in the next section, why this 

schedule is achievable for states to 

submit final plans. We discuss the 

timing of state plans in more detail in 

this section below. 

Discussed in the following sections 

are state plan submittal and timing, 

required components for initial 

submittals and the 2017 update, multistate plan submissions, process for EPA 

review of state plans, failure to submit 

a plan, state plan modifications 

(including modifications to interim and 

final CO2 emission goals), plan 

templates and electronic submittal, and 

legal bases regarding state plan process. 

2. State Plan Submittal and Timing 

The implementing regulations (40 

CFR 60.23) require that state plans be 

submitted to the EPA within 9 months 

of promulgation of the emission 

guidelines, unless the EPA specifies 

otherwise.836 For these 111(d) 

guidelines, the EPA is finalizing that 

each state must by September 6, 2016, 

either submit a final plan submittal or 

seek an extension to submit a final plan 

by September 6, 2018. In the case of a 

state electing to participate in the CEIP, 

this 2016 submittal must include a nonbinding statement of intent to 

participate in the program. To seek an 

extension of the September 6, 2016 

deadline until no later than September 

6, 2018, a state must submit an initial 

submittal by September 6, 2016, that 

addresses three required components 

sufficiently to demonstrate that a state is 

able to undertake steps and processes 

necessary to timely submit a final plan 

by the extended date of September 6, 

2018. If an extension is requested and 

granted, states must also submit a 2017 

update by September 6, 2017, that 

documents the state’s continued 

progress towards meeting the September 

6, 2018 final plan submittal deadline. 

In the proposal, EPA proposed a 13 

month final state plan submittal 

deadline, with a 1 year possible 

extension for states submitting 

individual state plans and a 2 year 

possible extension for states submitting 

multi-state plans as part of a multi-state 

region. The EPA received substantive 

comment on the achievability of these 

proposed deadlines for state plan 

submittals. Multiple commenters 

expressed concern that due to timing of 

legislative cycles (some of which are 

every 2 years), regulatory processes, and 

other necessary tasks, states would find 

it extremely difficult to submit plans in 

1 or 2 years, whether or not they were 

planning to submit as part of a multistate region. The EPA agrees based on 

this input that a schedule shorter than 

3 years will be challenging for many— 

though not all—states. In light of the 

comments received and in order to 

provide maximum flexibility to states 

while still taking timely action to reduce 

CO2 emissions, in this final rule the EPA 

is allowing for a 2 year extension until 

September 6, 2018, for both individual 

and multi-state plans, to provide a total 

of 3 years for states to submit a final 

plan if an extension is received. Based 

on comments received, information the 

EPA has regarding steps states have 

already begun taking towards plan 

development, and extensive experience 

with similar state plan submission 

deadlines under CAA section 110 SIPs, 

the EPA believes states will be able to 

submit final plans within 3 years by 

September 6, 2018, in the event states 

are not required to submit a final plan 

by September 6, 2016. We address the 

substantive requirements of initial 

submittals and the 2017 update in the 

next section. States that receive 2-year 

extensions may submit the final plan 

earlier than September 6, 2018, if they 

so choose. 

The EPA highlights that one purpose 

of the initial submittal is to encourage 

and potentially facilitate states to do 

necessary planning and engagement 

with stakeholders so states are able to 

submit an approvable final state plan by 

the extended deadline of September 6, 

2018. Some states have well-developed 

existing programs and the attendant 

legal authority underpinning such 

programs to more easily meet the 

September 6, 2016 deadline by 

submitting a final plan which largely 

contains or relies upon such existing 

programs.837 Based on comments and 

stakeholder feedback, however, the EPA 

anticipates that many states intending to 

develop and submit a final plan will 

seek the optional extension given the 

time it may take to undergo necessary 

legislative, stakeholder, and planning 

processes. The EPA acknowledges that 

the initial submittal of September 6, 

2016, is not essential to the ability of 

states to submit final plans by 

September 6, 2018, so that even without 

this 2016 deadline, the EPA could 

require states to meet the 2018 deadline. 

Even so, this earlier date in the 3 year 

planning process serves as a useful 

‘‘check-in’’ that provides several 

significant advantages. First, this earlier 

date provides all states an opportunity 

to understand what approaches other 

states are considering. Because there are 

significant benefits to regional 

cooperation, the EPA believes that a 

formal process to collect and then 

provide this information will help all 

states develop better plans. Second, 

because the guidelines provide 

significant flexibility, the ability for the 

EPA to provide early input to states who 

may be pursuing more innovative 

approaches will help ensure that all 

state plans are ultimately approvable. 

The EPA therefore believes the initial 

submittal is an appropriate means by 

which to offer the optional extension, 

and for reasons further described in 

section VIII.E.3, that the requirements of 

the initial submittal are achievable by 

September 6, 2016, so states will be able 

to develop and submit a plan that meets 

the requirements of the final emission 

guidelines and section 111(d) of the 

CAA by the extended date. 

Additionally, some states may not 

submit a state plan as required by the 

final emission guidelines and section 

111(d) of the CAA. For states that do not 

submit a state plan, the CAA gives the 

EPA express authority to implement a 

federal plan for sources in that state 

upon determination by the EPA that a 

state has failed to submit a state plan by 

the required date. For states that do not 

intend to submit a state plan to meet the 

obligations of this final rule, by 

promulgating a federal plan for affected 

EGUs in states that do not submit a plan 

by September 6, 2016, such affected 

EGUs would have a maximum of an 


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838 40 CFR 60.23(b). 

839See 40 CFR 49.1 to 49.11. 

840As stated previously, in the case of a state 

electing to participate in the CEIP, this 2016 

submittal must include a non-binding statement of 

intent to participate in the program. 

841Such stakeholders may include labor unions 

and workers that have an interest in the state plan, 

and communities whose economies are dependent 

on coal. 

842For example, 13 states were required to submit 

SIP revisions sufficient to regulate GHGs under the 

Prevention of Significant Deterioration (PSD) 

permitting requirements of the CAA within either 

3 weeks or 12 months in response to the EPA’s SIP 

call. See ‘‘Action To Ensure Authority To Issue 

Permits Under the Prevention of Significant 

Deterioration Program to Sources of Greenhouse 

Gas Emissions: Finding of Substantial Inadequacy 

and SIP Call’’, 75 FR 77698, (December 13, 2010). 

additional 2 years to plan for and 

determine compliance strategies than 

had promulgation of a federal plan been 

predicated on states failing to submit a 

plan by September 6, 2018. The EPA 

also notes that this final rule affords 

states and affected EGUs with many 

implementation flexibilities and 

approaches for state plans that the EPA 

itself may not have the authority to 

implement through a federal plan. 

Therefore, affected EGUs subject to a 

federal plan promulgated for a state that 

refuses to submit a state plan may 

benefit from an additional 2 years to 

plan for compliance with a federal plan 

with potentially fewer flexibilities. 

If no affected EGU is located within 

a state, the state must submit a letter to 

the EPA certifying that no such facilities 

exist by September 6, 2016.838 The EPA 

will publish a notice in the Federal 

Register to notify the public of receipt 

of such letters. If an affected EGU is 

later found to be located in that state, 

the state must submit a final plan 

addressing such affected EGU or the 

EPA will determine the state has failed 

to submit a plan as required by the 

emission guidelines and CAA section 

111(d), and begin the process of 

implementing a federal plan for that 

affected EGU. 

In the case of a tribe that has one or 

more affected EGUs located in its area 

of Indian country, if the tribe either does 

not submit a CAA section 111(d) plan or 

does not receive EPA approval of a 

submitted plan, the EPA has the 

responsibility to establish a CAA section 

111(d) plan for that area if it determines 

that such a plan is necessary or 

appropriate to protect air quality.839 See 

the proposed federal plan rulemaking 

for further information. 

The EPA notes that the current 

implementing regulations at 40 CFR part 

60 do not specify who has the authority 

to make a formal submission of the state 

plan to the EPA for review. In order to 

clarify who on behalf of a state is 

authorized to submit an initial 

submittal, 2017 update, final state plan 

(or negative declaration, if applicable), 

and any revisions to an approved plan, 

the EPA has included a requirement in 

this final rule mirroring that of the 

requirement in 40 CFR part 51 App. 

V.2.1.(a) with respect to SIPs that 

identifies the Governor of a state as the 

authorized official for submitting the 

state plan to the EPA. If the Governor 

wishes to designate another responsible 

official the authority to submit a state 

plan, the EPA must be notified via letter 

from the Governor prior to the 2016 

deadline for plan submittal so that they 

have the ability to submit the initial 

submittal or final plan in the State Plan 

Electronic Collection System (SPeCS). If 

the Governor has previously delegated 

authority to make CAA submittals on 

the Governor’s behalf, a state may 

submit documentation of the delegation 

in lieu of a letter from the Governor. The 

letter or documentation must identify 

the designee to whom authority is being 

designated and must include the name 

and contact information for the designee 

and also identify the state plan 

preparers who will need access to 

SPeCS discussed in section VIII.E.8. A 

state may also submit the names of the 

state plan preparers via a separate letter 

prior to the designation letter from the 

Governor in order to expedite the state 

plan administrative process. Required 

contact information for the designee and 

preparers includes the person’s title, 

organization and email address. The 

EPA recommends this information be 

submitted early in the state planning 

process to allow sufficient time for 

completion of SPeCS registration so that 

those authorized to use the system are 

provided access. 

3. Components of an Initial Submittal 

and 2017 Update 

As noted, states may request a 2-year 

extension to submit a final plan through 

making an initial submittal by 

September 6, 2016. For the extension to 

be granted, the EPA is finalizing that the 

initial submittal must address three 

required components sufficiently to 

demonstrate that a state is able to 

undertake steps and processes necessary 

to timely submit a final plan by the 

extended date of September 6, 2018: 840

• An identification of final plan approach 

or approaches under consideration, including 

a description of progress made to date. 

• An appropriate explanation for why the 

state requires additional time to submit a 

final plan by September 6, 2018. 

• Demonstration or description of 

opportunity for public comment on the 

initial submittal and meaningful engagement 

with stakeholders,841 including vulnerable 

communities, during the time in preparation 

of the initial submittal and plans for 

engagement during development of the final 

plan. 

During the public comment period, 

multiple commenters stated that the 

proposed timeframe for states to submit 

an initial submittal was not achievable, 

citing, among other things, the number 

of decisions needed to be made by a 

state or states, and that the EPA needed 

to clarify the requirements for an initial 

submittal. Multiple commenters also 

expressed concern that the requirements 

for an initial submittal required final 

decisions to be made by states, and that 

the initial submittal deadline was not 

enough time for states to make these 

decisions. 

It is important to note that the EPA is 

not requiring the adoption of any 

enforceable measures or final decisions 

in order for the state to address any of 

the initial submittal components by 

September 6, 2016. The EPA believes 

the absence of requiring enforceable 

measures to be included with the initial 

submittal greatly supports the ability of 

states intending to develop a final state 

plan to submit an initial submittal by 

September 6, 2016. States are required 

to submit enforceable measures 

supported by technically complex 

documentation, such as modeling, and 

adopted through state public 

participation and regulatory or 

legislative processes as part of SIPs 

under other parts of the CAA within 

timeframes comparable to the time the 

EPA is providing for initial 

submittals.842

In order to further address the 

commenters’ concerns regarding 

possible ambiguity of the requirements 

for an initial submittal so that an 

extension is granted, the EPA is 

providing clarity regarding the required 

components for an initial submittal. 

Regarding the component that states 

address an appropriate explanation for 

an extension, the EPA proposed that 

appropriate explanations for seeking an 

extension beyond 2016 for submitting a 

final plan include: A state’s required 

schedule for legislative approval and 

administrative rulemaking, the need for 

multi-state coordination in the 

development of an individual state plan, 

or the process and coordination 

necessary to develop a multi-state plan. 

In this final rule, the EPA is finalizing 

these as appropriate explanations for 

seeking an extension beyond 2016, but 

makes clear—as explained further 

below—that other appropriate 

explanations will be acceptable as well. 

It is important to note that the initial 

submittal does not require legislation 


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and/or regulations to be passed prior in 

order for the state to be granted an 

extension, but the initial submittal 

should describe any concrete steps the 

state has already taken on legislation 

and/or administrative rulemaking and 

detail what the remaining steps are in 

those processes before a final plan can 

be submitted. The EPA also sought 

comment on other circumstances for 

which an extension of time would be 

appropriate, and also whether some 

explanations for extensions should not 

be permitted. Commenters stated that 

states should be able to seek extensions 

whenever an extension can be 

reasonably justified, and that the EPA 

should take at face value states’ good 

faith efforts by accepting any state 

assertion that more time is needed to 

develop a plan unless there is clear 

evidence to the contrary. The EPA 

believes there may be appropriate 

explanations states may submit in 

addition to the ones described in this 

final rule sufficient to demonstrate that 

a state is able to undertake steps and 

processes necessary to timely submit a 

final plan by the extended date of 

September 6, 2018. Given the 

opportunity for states to submit 

appropriate explanations other than the 

ones detailed here, the EPA believes 

addressing this component requiring an 

appropriate explanation for an 

extension is easily achievable by 

September 6, 2016. 

In order to additionally clarify the 

required components of the initial 

submittal, the following are types of 

explanations of information states may 

provide as part of the initial submittal 

to sufficiently address each of the three 

required components for getting an 

extension: 

• Details on whether a state is considering 

a single or multi-state plan, a plan that meets 

the CO2 emission performance rates or state 

CO2 rate or mass emission goal, and/or an 

emission standards or state measures plan 

type. 

• A description of how the state intends to 

address development of the required 

components of the final state plan, including 

describing what actions have already been 

taken, what steps remain, and the schedule 

for completing those steps. 

• A commitment to maintain any existing 

measures the state intends to rely upon for 

its final plan in order to achieve the 

necessary reductions once the performance 

period begins. 

• Describing public participation 

opportunities such as stakeholder and 

community meetings, or public hearings, 

throughout the 3 year plan development 

process. This could also include leverage of 

public participation approaches that states 

already use to identify and engage potentially 

affected communities. 

The EPA emphasizes the required 

initial submittal components are 

intended to provide a reasonable 

pathway for states to demonstrate 

whether they will be able to submit an 

approvable plan by the extended date of 

September 6, 2018. The EPA also 

anticipates that through the requirement 

to address these components, the initial 

submittal will also facilitate state 

planning and stakeholder engagement, 

particularly as one component requires 

the public and stakeholders to have an 

opportunity to comment on the initial 

submittal. As previously described, 

these components do not require final 

decisions to be made by states, and this 

is further illustrated by the clarifications 

on how states may meet each of the 

three required components. 

Accordingly, the EPA believes none of 

these components is onerous for states 

to address in an initial submittal by the 

September 6, 2016 deadline. To further 

underscore this point, the EPA is further 

explaining the clarifying examples 

listed above of how states may address 

the three required components, and 

highlighting the achievability of these 

examples for states to address through 

the initial submittal by September 6, 

2016. 

For identification of the final plan 

approach or approaches the state is 

considering, and description of progress 

made to date, states could identify 

whether the state is considering the 

option of the CO2 emission performance 

rates, a rate-based CO2 goal, or a massbased CO2 goal, and whether the state is 

intending to pursue a single-state or 

multi-state plan. Stakeholders 

commented that states will not be far 

enough along in the rule development 

process to have made these decisions. 

Commenters also stated that many state 

legislatures would need to pass 

legislation giving state environmental 

agencies legal authority and direction 

before they could begin to make 

decisions such as rate or mass-based 

approach or single or multi-state plan 

submittal. In order to address the 

commenters’ concerns, the EPA wishes 

to clarify that state approaches 

identified in the initial submittal do not 

need to be final and/or formalized 

through a state legislature, and that 

states may opt to identify pursuit of 

more than one approach at the same 

time, or to indicate the status of the 

deliberation of this issue within the 

state. 

The EPA received substantive 

comment regarding the potential 

adverse consequences for states 

pursuing a multi-state approach and 

receiving an extension until 2018, 

where, for various reasons, a state or 

states then decide(s) to pursue the single 

state approach. Commenters viewed this 

as being potentially problematic since, 

as proposed, a single state could only 

receive an extension until 2017, and if 

a multi-state plan effort does not work 

out the deadline for seeking the 

extension until 2017 would have 

passed. The EPA notes finalizing a 2 

year extension that is available for any 

state, whether they are pursuing an 

individual state plan or a multi-state 

plan resolves the commenters’ concern 

about conflicting extension deadlines if 

states involved in a multi-state effort 

decide not to pursue the multi-state 

approach. Importantly, such 

identification in an initial submittal 

does not obligate the state to then 

actually adopt that approach in their 

final plan as the EPA acknowledges that 

based on state processes and public 

input through plan development during 

the extended submission period, a state 

may end up adopting a state plan 

approach more suitable to the needs of 

that state and its affected EGUs than 

previously identified in the initial 

submittal. 

States can also describe progress 

made to date by identifying steps 

already taken to address development of 

the final state plan, as the EPA 

recognizes that states in general have 

already taken a number of steps to 

prepare for state plan development to 

meet the obligations of this rule. For 

example, since proposal, states have: 

Begun exploring tradeoffs among 

various state plan approaches such as 

individual versus multistate 

coordination, increased utilization of 

demand-side EE and RE programs, and 

implementing rate-based versus massbased programs; increased their 

understanding of existing state programs 

and policies that reduce carbon 

emissions; built relationships and 

communications between key state 

institutions such as environmental 

agencies, PUCs, governors’ offices, and 

energy regulators; hosted public 

stakeholder meetings to educate and 

solicit input from the public; and begun 

discussing state processes for 

developing potential state plans. States 

may meet the first required component 

by describing steps such as these 

already undertaken. 

The EPA underscores that states may 

easily address the first component of the 

initial submittal by describing such 

steps, and also address the second 

required component by identifying next 

steps (which may be a natural extension 

of these already implemented activities), 

and laying out a schedule for 

development of a final plan. States that 

have taken these steps would especially 


tkelley on DSK3SPTVN1PROD with BOOK 2
64858 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

843 Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. http://epa.gov/environmentaljustice/

resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. 

844 Ibid. 

845Considering Environmental Justice in 

Permitting. http://www.epa.gov/

environmentaljustice/plan-ej/

permitting.html#actions. 

be able to address the component 

regarding an appropriate explanation for 

an extension as the EPA recognizes the 

substantial work such states have begun 

to put towards development of state 

plans, and the continuation of this work 

justifies additional time to complete 

necessary steps to result in an 

approvable state plan. The EPA 

emphasizes that for states who intend to 

submit a final plan and need an 

extension, the components of the initial 

submittal are not intended to require 

burdensome final action by states by 

September 6, 2016, but to identify a 

viable path to completing a final plan by 

September 6, 2018. 

An initial submittal that contains a 

commitment to maintain any existing 

measures the state intends to rely upon 

for its final plan in order to get the 

necessary reductions once the 

performance period begins (e.g. RE 

standards and demand-side EE 

programs the state intends to rely upon 

through a state measures plan type), at 

least until the final plan is approved, 

also addresses the requirement that 

states provide an appropriate 

explanation for an extension. Given the 

state’s request for additional time prior 

to putting in place enforceable measures 

to reduce CO2, it would be reasonable 

and appropriate, and in keeping with 

the goals of 111(d) to ensure that any 

existing CO2 reduction measures that 

the state intends to rely upon remain in 

place while the state is developing a 

final plan. Such commitment would 

demonstrate that the state is taking 

substantive steps towards successful 

development of a final plan within 3 

years. 

Regarding the required public 

participation component of the initial 

submittal, the EPA believes this 

requirement is both achievable for states 

to submit an initial submittal by the 

September 6, 2016 deadline, and 

provides a benefit in facilitating state 

plan development so that states are 

more likely to be able to submit a final 

plan within 3 years if the extension is 

granted. The EPA can use a comment 

opportunity on the initial submittal to 

advise the state whether aspects of the 

draft initial submittal and overall plan 

development are appropriate for 

purposes of meeting the requirements of 

the final rule so that the state will be 

able to procure the extension through an 

acceptable initial submittal and submit 

a final plan by the extended deadline. 

The EPA notes the comment period on 

the initial submittal is only one 

opportunity the EPA has to assist a state 

in the state plan development process. 

The EPA has historically worked with 

states throughout the state plan 

development process to help ensure that 

the state plan is approvable once 

submitted to the EPA, and expects this 

level of engagement with states to 

continue throughout the plan 

development process. This requirement 

will also facilitate early identification of 

concerns stakeholders and the public 

may have with aspects of a final plan 

the state is considering. As states have 

longtime and extensive experience with 

responding to public comments in 

numerous contexts, including in the 

context of other CAA programs such as 

section 110 SIP development and in 

permit issuance under NSR and Title V, 

the EPA anticipates states will be able 

to timely address the initial submittal 

public participation. 

As previously discussed, because 

certain communities have a potential 

likelihood to be impacted by state plans, 

the EPA believes that the existing public 

participation requirements under 40 

CFR 60.23 are effectuated for the 

purposes of this final rule by states 

engaging in meaningful, active ways 

with such communities. Therefore, the 

public participation component of the 

initial submittal includes meaningful 

engagement with vulnerable 

communities, throughout the state plan 

development process and including 

through the initial submittal. In order to 

demonstrate to the EPA that states are 

actively engaging with communities, 

states could provide in their initial 

submittal a summary of steps they have 

already taken to engage the public and 

how they intend to continue meaningful 

engagement, including with vulnerable 

communities, during the additional time 

(if an extension is granted) for 

development of the final plan. In 

addition to approaches that states 

already use to identify and engage 

potentially affected communities, the 

EPA encourages states to use the 

proximity analysis conducted for this 

rulemaking (which is described in 

section IX.A) as a tool to help them 

identify overburdened communities that 

could be potentially impacted by their 

plans. Other tools, such as EJ screen, 

can also be helpful. The EPA in its 

continued outreach with states during 

the implementation phase will also 

provide resources to assist them in 

engaging with communities. The EPA 

believes that through the provision of 

these resources states will also more 

easily be able to address this required 

component of the initial submittal 

regarding public engagement, including 

with vulnerable communities, by 

September 6, 2016. 

In addition to the resources the EPA 

intends to provide to states, there are 

existing resources states can take 

advantage of to address this component 

as well. On the steps that states could 

take to engage vulnerable communities 

in a meaningful way, the Agency 

recommends that states consult the 

EPA’s May 2015 Guidance on 

Considering Environmental Justice 

During the Development of Regulatory 

Actions. In this document, the EPA 

defines meaningful involvement as 

ensuring that ‘‘potentially affected 

community members have an 

appropriate opportunity to participate 

in decisions about a proposed activity 

(i.e., rulemaking) that may affect their 

environment and/or health; the 

population’s contribution can influence 

the EPA’s [regulatory authority’s] 

rulemaking decisions; the concerns of 

all participants involved will be 

considered in the decision-making 

process; and the EPA [decision-makers] 

will seek out and facilitate the 

involvement of those potentially 

affected by the EPA’s [or other 

regulatory authority’s] rulemaking 

process.’’ 843 Additionally, this guidance 

document also encourages those writing 

rules to consider the positive impacts 

that a rulemaking will have on 

communities).844 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 Web site.845 Both of the 

resources discussed above can add to 

what states may already have in place 

to effectively engage vulnerable 

communities in the rulemaking process. 

The EPA recommends that as part of 

their meaningful engagement with 

vulnerable communities, states work 

with communities to ensure that they 

have a clear understanding of the 

benefits and any potential adverse 

impacts that a state plan might have on 

their overburdened communities and 

that there is a clear process for states to 

respond to input from communities. 

If a state seeks an extension by 

submitting an appropriate initial 

submittal addressing the three required 

components as described above by 

September 6, 2016, the EPA will review 

the submittal. If the state does not 

submit an initial submittal by 

September 6, 2016, that contains the 

three required components, the EPA 


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will notify the state by letter, within 90 

days, that the agency cannot grant the 

extension request based the state’s 

initial submittal. The EPA will notify a 

state by letter only if the initial 

submittal does not address the three 

required components. An extension for 

submitting a final plan will be deemed 

granted if the EPA does not deny the 

extension request based on the initial 

submittal. The EPA has determined this 

approach is authorized by, and 

consistent with, 40 CFR 60.27(a) of the 

implementing regulations. 

For states that request and receive a 

2-year extension, the state must submit 

an update halfway through that 

extension, by September 6, 2017. In the 

proposal the EPA included a 

requirement regarding a 2017 check in. 

Because the EPA is finalizing that states 

are able to get a 2-year extension 

regardless of whether they are 

submitting an individual or multi state 

final plan, the EPA believes it 

appropriate to ensure through the 2017 

update that the state is making 

continuous progress on its initial 

submittal and that it is on track to meet 

the final plan submittal deadline of 

September 6, 2018. The EPA will also be 

able to use the information provided 

through the 2017 update to further assist 

states in plan development. 

The final rule requires that states 

address in the 2017 update the 

following components: 

• A summary of the status with respect to 

required components of the final plan, 

including a list of which components are not 

yet complete. 

• A commitment to a plan approach (e.g., 

single or multi-state, rate or mass emission 

performance level), including draft or 

proposed legislation and/or regulations. 

• An updated comprehensive roadmap 

with a schedule and milestones for 

completing the plan, including progress to 

date in developing a final plan and steps 

taken in furtherance of actions needed to 

finalize a final plan. 

In order to assess whether a state is on 

track to submit a final plan by the 2018 

extension deadline, the EPA is requiring 

that the 2017 update must contain a 

progress update on components from 

the initial submittal and a list of which 

final plan components are still not 

complete. 

The EPA is also requiring that the 

2017 update include a commitment to 

the type of plan approach the state will 

take in the final plan submittal. During 

the public comment period, many 

commenters stated that legislative 

action would be required to enact this 

final rule at the state level, and that the 

proposal did not provide enough time 

for legislative action or other regulatory 

actions needed for a state to be granted 

an extension. In order to respond to 

these comments, the EPA is clarifying 

that proposed or passed legislation or 

regulations are not required in the 

initial submittal due by September 6, 

2016. While a state may indicate 

consideration of multiple state plan 

approaches in the initial submittal, the 

EPA is requiring that the state commit 

to one approach in the 2017 update. 

This commitment must include draft or 

proposed legislation or regulations that 

must become final at the state level 

prior to submitting a final plan 

submittal to the EPA. While 

commenters expressed concern with not 

being able to have legislation enacted in 

time to receive an extension until 2018, 

the EPA has determined that 2 years is 

a reasonable timeframe for a state to 

decide on the type of approach it will 

take in the final plan submittal and to 

draft legislation or regulations for this 

approach in order to timely meet the 

extended September 6, 2018 deadline. 

4. Multi-State Plan Submittals 

For states wishing to participate in a 

multi-state plan, the EPA is finalizing 

three forms of submittal that states may 

choose for the submittal of a multi-state 

plan. 

First, the EPA is finalizing its 

proposed approach where one multistate plan submittal is made on behalf 

of all participating states. The joint 

submittal must be signed by authorized 

officials for each of the states 

participating in the multi-state plan and 

would have the same legal effect as an 

individual submittal for each 

participating state. The joint submittal 

must adequately address plan 

components that apply jointly for all 

participating states and for each 

individual state in the multi-state plan, 

including necessary state legal authority 

to implement the plan, such as state 

regulations and statutes. Because the 

multi-state plan functions as a single 

plan, each of the required plan 

components (e.g., plan emission goals, 

program implementation milestones, 

emission performance checks, and 

reporting) would be designed and 

implemented by the participating states 

on a multi-state basis. 

The EPA received comments from 

states requesting flexibility for multistate plan submittals. In response to 

these comments, the EPA is also 

finalizing two additional options on 

which it solicited comment. First, states 

participating in a multi-state plan can 

provide a single submittal—signed by 

authorized officials from each 

participating state—that addresses 

common plan elements. This option 

requires individual participating states 

to provide supplemental individual 

submittals that provide state-specific 

elements of the multi-state plan. The 

common multi-state submittal must 

address all relevant common plan 

elements and each individual 

participating state submittal must 

address all required plan components 

(including common plan elements, even 

if only through cross reference to the 

common plan submittal). Under this 

approach, the combined common 

submittal and each of the individual 

participating state submittals would 

constitute the multi-state plan 

submitted for EPA review. The joint 

common submittal must be signed by 

authorized officials for each of the states 

participating in the multi-state plan and 

would have the same legal effect as an 

individual submittal for each 

participating state. 

Second, the EPA is finalizing an 

approach where all states participating 

in a multi-state plan separately make 

individual submittals that address all 

elements of the multi-state plan. These 

submittals would need to be materially 

consistent for all common plan elements 

that apply to all participating states, and 

would also address individual statespecific aspects of the multi-state plan. 

Each individual state plan submittal 

would need to address all required plan 

components. The EPA encourages states 

participating in this type of multi-state 

plan to use as much common material 

as possible to ease review of the state 

plans. 

These approaches will provide states 

with flexibility in addressing 

contingencies where one or more states 

submit plan components that are not 

approvable. In such instances, these 

options simplify the EPA’s approval of 

remaining common or individual 

portions of a multi-state plan and help 

address contingencies during plan 

development where a state fails to 

finalize its participation in a multi-state 

plan, with minimal disruption to the 

submittals of the remaining 

participating states. These additional 

submittal approaches also facilitate 

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 ratebased 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 


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64860 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

846The 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. 

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 

multi-state plan, withdrawing from the 

multi-state plan, or failing to implement 

the multi-state plan, states may include 

express severability clauses if their 

multi-state plan is able to stand without 

further revision if one of the situations 

described above occurs. The severability 

clause must specify how the remainder 

of the multi-state plan or individual 

state plan would continue to function 

with the withdrawal of a state or states, 

and may also include pre-specified 

revisions. The EPA will evaluate the 

appropriateness of such a clause as part 

of its review of the multi-state plan 

submittal. 

5. Process for EPA Review of State Plans 

Our proposal laid out the basic steps 

for the EPA’s review and action on 

submitted state plans and, at some 

length, discussed the required 

components of state plans, as further 

described in the preceding sections. We 

received a number of thoughtful and 

helpful comments on these issues. We 

are finalizing the basic requirements in 

this rule and are proposing, in the 

companion proposed federal plan under 

section 111(d), some additional 

procedural elements we believe will be 

helpful to states, stakeholders and the 

EPA moving forward. 

Following the September 6, 2016 

deadline for state plan submittals, the 

EPA will review plan submittals. For a 

state that submits an initial submittal by 

September 6, 2016, and requests an 

extension of the deadline for the 

submission of a final state plan 

submittal, the EPA will determine if the 

initial submittal meets the minimum 

requirements for an initial submittal. If 

the state does not submit an initial 

submittal by September 6, 2016, that 

contains the three required components, 

the EPA will notify the state by letter, 

within 90 days, that the agency cannot 

grant the extension request based the 

state’s initial submittal. If the initial 

submittal meets the minimum 

requirements specified in the emission 

guidelines, the state’s request for a 

deadline extension to submit a final 

plan submittal will be deemed granted, 

and the final plan submittal must be 

submitted to the EPA by no later than 

September 6, 2018. 

After receipt of a final plan submittal, 

the EPA will review the plan submittal 

and, within 12 months, approve or 

disapprove the plan through a noticeand-comment rulemaking process 

publicized in the Federal Register, 

similar to that used for acting upon SIP 

submittals under section 110 of the 

CAA. The implementing regulations 

currently provide for the EPA to act on 

a final plan within 4 months after the 

deadline for submission, which is 

consistent with versions of section 110 

prior to the 1990 Amendments to the 

CAA. 40 CFR 60.27(b). To be consistent 

with the current version of section 110, 

the EPA intends to adopt a timeline of 

12 months to review final plan 

submittals upon receipt of complete 

submittals, as is generally consistent 

with the timing requirements of section 

110 with respect to complete SIP 

submittals. Such a timeline would also 

provide the EPA with adequate time for 

review and rulemaking procedures, and 

ensuring an opportunity for public 

notice and opportunity for comment. 

We note, however, that we proposed 

this timeline for review and action on 

state plans in our proposal, but our 

proposal was specific to the timeline for 

state plans submitted pursuant to this 

rule rather than for state plans 

submitted under 111(d) generally.846 We 

are finalizing as part of this rule that 

state plans submitted to meet the 

requirements of this rule will be 

reviewed and acted upon by the EPA 

within 12 months of submission. 

Because such timeline would be 

appropriate to be made to 111(d) state 

plans more generally, we are also 

proposing the appropriate revisions to 

the implementing regulations as part of 

the federal plan proposal for section 

111(d). 

In addition, while the proposal and 

this final rule lay out in considerable 

detail the required components of a 

state plan, the EPA believes that it 

would also be helpful to include in the 

rule a completeness determination 

process, similar to that used for SIP 

submittals under section 110, which 

will allow the EPA to determine 

whether a final plan submittal contains 

the components necessary to enable the 

EPA to determine through notice and 

comment rulemaking whether such 

submittal complies with the 

requirements of section 111(d). This is 

a procedural requirement under CAA 

section 110(k)(1) for SIPs, and the EPA 

believes this requirement is appropriate 

to establish under section 111(d)’s 

direction to the EPA to prescribe 

through regulations a procedure similar 

to that provided by section 110. 

However, because the EPA did not 

propose such regulations as part of the 

proposal for this action, the EPA is 

proposing such regulations as part of the 

federal plan proposal for section 111(d). 

The EPA notes that this preamble (in 

section VIII.D) and final rule lay out 

required components of state plans and 

all the requirements for a state plan 

submittal, and therefore states have the 

necessary information at this time to 

develop state plans. The upcoming 

completeness criteria will not add to or 

change these required components, but 

only add a procedural step that allows 

the EPA to identify whether there are 

absent or insufficient components in the 

plan submittal that would render the 

EPA unable to act on such submittal 

because it is incomplete. As we further 

explain in the federal plan proposal, a 

determination by the EPA that a plan 

submittal is incomplete has the effect of 

a state having a still-pending statutory 

obligation to submit a plan that meets 

the requirements of section 111(d). 

The EPA is planning to propose an 

amendment to the section 111(d) 

implementing regulations that will add 

the partial approval/disapproval and 

conditional approval mechanisms in 

section 110(k)(3) and (4) to the 

procedure for acting on section 111(d) 

plans. The input the agency received in 

response to the proposal for these 

guidelines indicated that the flexibility 

provided by these mechanisms could be 

useful getting state plans in place. The 

EPA agrees, and is proposing to amend 

the implementing regulations as part of 

the rulemaking for the federal 111(d) 

plan. The EPA is not taking final action 

on these changes in this action. 

The later timing for our action on 

partial approval/disapproval and 

conditional procedures does not create 

any issue with finalizing this rule. 

These procedural adjustments will only 

come into play after states have 

submitted their plans and the EPA is 

required to act on them, and we intend 

to finalize these procedural changes 

prior to September 6, 2016, when the 

first plan submittals would occur. Until 

then, the EPA believes that every plan 

is submitted with the intent to be fully 

approvable and there is no need for 

states to rely on the possibility of these 

procedures when developing their 

plans. Conditional approval and partial 

approval/disapproval should be used to 

deal with approvability issues that arise 

despite the best efforts of states and the 

EPA to work together to make sure a 

submittal in the first instance is fully 

approvable. The EPA plans to finalize 

any changes in the implementing 

regulations 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. 


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6. Failure To Submit a Plan 

If a state does not submit a final plan 

submittal by the applicable deadline, or 

submits a final plan the EPA determines 

to be incomplete, the EPA will notify 

the state by letter of its failure to submit. 

The EPA will publish a Federal Register 

notice informing the public of its 

finding of failure to submit. Upon a 

finding of failure to submit for a state, 

a regulatory clock will run requiring the 

EPA to promulgate a federal plan for 

such state no later than 1 year after the 

EPA makes the finding unless the state 

submits, and the EPA approves, a state 

plan during this time. Refer to the 

federal plan proposal for more details 

on how and when a federal plan would 

be triggered. 

7. State Plan Modifications 

a. Modifications to an approved state 

plan. 

During the course of implementation 

of an approved state plan, a state may 

wish to update or alter one or more of 

the enforceable measures in the state 

plan, or replace certain existing 

enforceable measures with new 

measures. The EPA received broad 

support for allowing states to submit 

modifications to approved state plans, 

and we agree that this is an important 

aspect of this program. In this 

rulemaking, therefore, the EPA is 

finalizing that a state may revise its state 

plan, and states in a multi-state plan 

may revise their joint plan. Consistent 

with the timing for final plan submittals 

originally submitted by states, the EPA 

will act on state plan revisions within 

12 months of a complete submittal. The 

EPA expects that the long plan 

performance timeframes in this final 

rule and flexibility provided to states in 

developing state plans will lessen the 

need for modifications to approved state 

plans. 

A state may enter or exit a multi-state 

plan through a plan modification, with 

certain limitations. Multiple 

commenters stated that the EPA should 

clarify the plan modification process in 

such instances. 

Where a state with a single-state 

approved plan seeks to join a multi-state 

plan, the state may submit a 

modification of its plan indicating that 

it is joining the multi-state plan and 

including the necessary plan 

components under the multi-state plan. 

The current participants of the multistate plan will also need to submit a 

plan modification, to acknowledge the 

new state participant and to recalculate 

the multi-state rate-based or mass-based 

CO2 goal. Functionally, both the 

modification of the single-state plan of 

the new participant and the multi-state 

plan of the current plan participants 

could be addressed through the same 

plan modification submittal or 

addressed under a plan modification 

submittal comparable to the alternate 

formats for multi-state plan submittals 

addressed in section VIII.E.4. 

The entry or exit of a state to/from a 

multi-state plan involves the 

recalculation of the multi-state ratebased or mass-based CO2 goal for 

affected EGUs in the participating states. 

The recalculated multi-state rate-based 

or mass-based CO2 goal must take into 

account and ensure achievement of the 

individual state rate-based or massbased CO2 goal for any state that is 

joining the multi-state plan. If 

implementation of the individual state 

plan has triggered corrective measures 

or backstop emission standards prior to 

the plan modification, as described in 

section VIII.F.3, the modification must 

take into account the need to make up 

for any shortfall in CO2 emission 

performance in the individual state plan 

prior to joining the multi-state plan. 

Where one or more states are leaving a 

multi-state plan through a plan 

modification, the process is similar and 

the same considerations must be taken 

into account in connection with the 

states that are leaving the multi-state 

plan. 

As a result of these requirements and 

considerations, the EPA is finalizing 

certain requirements for multi-state plan 

modifications. A multi-state plan 

modification may be submitted to the 

EPA at any time. However, an approved 

multi-state plan modification may only 

take effect at the beginning of a new 

interim or final plan performance 

period. These requirements are 

necessary to ensure that the emission 

performance rates or state rate-based or 

mass-based CO2 goals in the emission 

guidelines are achieved. In addition, 

such requirements for the timing of the 

effective date of multi-state plan 

modifications are necessary for 

coordination of the implementation of 

multi-state plans, especially where such 

plans include a multi-state emission 

trading approach. This approach is also 

consistent with the approach the EPA is 

proposing for the implementation of 

federal plan, where relevant for a 

state(s). 

The EPA solicited comment on 

whether, for new projections of 

emission performance included in a 

submitted plan modification, the 

projection methods, tools, and 

assumptions used should match those 

used for the projection in the original 

demonstration of plan performance, or 

should be updated to reflect the latest 

data and assumptions, such as 

assumptions for current and future 

economic conditions and technology 

cost and performance. Comments 

received on this topic were generally 

supportive of allowing the use of 

updated data in state plan 

modifications, citing that states should 

have the ability to determine whether 

the original data and assumptions or 

updated data and assumptions are 

appropriate. The EPA is finalizing that 

new projections of emission 

performance, the projection methods, 

tools, and assumptions do not have to 

match those used for the projection in 

the original demonstration of plan 

performance; they can be updated to 

reflect the latest data and assumptions, 

such as assumptions for current and 

future economic conditions and 

technology cost and performance. 

As discussed in more detail in section 

VIII.G.2, the final rule has several 

measures to ensure that it does not 

interfere with the industry’s ability to 

maintain reliability. One such measure 

is that if a state cannot address a 

reliability issue in accordance with an 

approved state plan, the state can 

submit a request to the EPA to modify 

the state plan. See section VIII.G.2 for a 

more detailed discussion of this issue. 

The EPA is not finalizing any 

circumstances under which a state may 

or may not revise its state plan, with the 

exception that a state may not revise its 

state plan in a way that results in the 

affected EGU or EGUs not meeting the 

requisite CO2 emission performance 

levels. 

b. Modifications to interim and final 

CO2 emission goals. 

As discussed in section VII, the final 

rule specifies that the state interim and 

final CO2 emission goals for affected 

EGUs in a state may be adjusted to 

address changes within a state’s fleet of 

affected EGUs. If these changes occur 

before a state submits its initial 

submittal or final plan, the state should 

indicate in its submittal the 

circumstance that necessitates the goal 

adjustment and the revised interim or 

final CO2 emission goal. If the 

circumstances occur after a state has an 

approved plan, a state must submit a 

modification to its approved plan. The 

plan revision submittal must indicate 

the circumstance that necessitates the 

goal adjustment, the revised interim 

and/or final CO2 emission goal, and the 

adjustments to the enforceable measures 

in the plan. 

8. Plan Templates and Electronic 

Submittal 

The EPA is finalizing the requirement 

that submissions related to this program 


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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 noneditable version, the EPA is also 

requiring that all plan components 

designated as federally enforceable must 

be submitted in an editable version as 

well, as discussed below. 

a. Submittal of an editable version of 

federally enforceable plan components. 

To ensure that the EPA has the ability 

to identify, evaluate, merge, update and 

track federally enforceable plan 

components in a timely and 

comprehensive manner, the EPA is 

requiring states to submit an editable 

copy of the specific plan components in 

their submittals that are designated as 

federally enforceable, either effective 

upon the EPA plan approval or as a state 

plan backstop measure. The editable 

version is in addition to the noneditable version. Examples of editable 

file formats include Microsoft Word, 

Apple Pages and WordPerfect. 

b. Revisions to an approved plan. 

States shall provide the EPA with 

both a non-editable and editable copy of 

any submitted revision to existing 

approved federally enforceable plan 

components, including state plan 

backstop measures. The editable copy of 

any such submitted plan revision must 

indicate the changes made, if any, to the 

existing approved federally enforceable 

plan components, using a mechanism 

such as redline/strikethrough. This 

approach to identifying the changes 

made to the existing federally 

enforceable plan components is 

consistent with the criteria for 

determining the completeness of SIP 

submissions set forth in Section 2.1(d) 

of Appendix V to 40 CFR part 51. 

c. Electronic submittal. 

It is the EPA’s experience that 

electronic submittal of information has 

increased the ease and efficiency of data 

submittal and data accessibility. The 

EPA is developing the SPeCS, a web 

accessible electronic system to support 

this requirement that will be accessed at 

the EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). The EPA 

will pre-register authorized officials and 

plan preparers in CDX. See section 

VIII.E.2 for additional information on 

the pre-registration process for 

authorized officials and plan preparers. 

Detailed instructions for accessing CDX 

and SPeCS will be outlined in the 

‘‘111(d) SPeCS User Guide: How to 

submit state 111(d) plan material to 

EPA’’ which will be available on the 

EPA’s Clean Power Plan Toolbox for 

States. The EPA will provide SPeCS 

training for states prior to the state plan 

submittal due date. 

Once in CDX, SPeCS can be selected 

from the Active Program Service List. 

The preparer (e.g., state representative 

compiling a state plan submittal) 

assembles the submission package. The 

preparer can upload files and complete 

electronic forms. However, the preparer 

may not formally submit and sign 

packages. Only registered authorized 

officials may submit and sign for the 

state with the exception of draft 

submittals. The EPA’s intent is to allow 

submittal of draft plans or parts of plans 

for early EPA review prior to formal 

submission by the authorized official 

and will allow preparers, as well as 

authorized officials, to submit draft 

documents. The authorized official will 

be able to assemble submission 

packages and will be able to modify 

submission packages that a preparer has 

assembled. The key difference between 

the preparer and the authorized official 

is that the authorized official can submit 

and sign a package for formal EPA 

review using an electronic signature. In 

the case of a multi-state plan, each 

participating state’s authorized official 

must provide an electronic signature. 

The process has been designed to be 

compliant with the Cross-Media 

Electronic Reporting Rule (CROMERR), 

under 40 CFR part 3, which provides 

the legal framework for electronic 

reporting under all of the EPA’s 

environmental regulations. The 

framework includes criteria for assuring 

that the electronic signature is legally 

associated with an electronic document 

for the purpose of expressing the same 

meaning and intention as would a 

handwritten signature if affixed to an 

equivalent paper document. In other 

words, the electronic signature is as 

equally enforceable as a paper signature. 

For more information on CROMERR, see 

the Web site: http://www.epa.gov/

cromerr/. States who claim that a state 

plan submittal or supporting 

documentation includes confidential 

business information (CBI) must submit 

that information on a compact disc, 

flash drive, or other commonly used 

electronic storage media to the EPA. The 

electronic media must be clearly marked 

as CBI and mailed to U.S. EPA/OAQPS/ 

CORE CBI Office, Attention: State and 

Local Programs Group, MD C539–01, 

4930 Old Page Rd., Durham, NC 27703. 

The EPA received a number of 

comments on the electronic submittal of 

state plans. Some commenters preferred 

the option to submit electronically 

rather than the requirement to do so. 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 twoway business communication between 

states and the EPA, will guide states 

through the submittal process to ensure 

submission of all required plan 

components, and will enable states to 

submit proposed plans to the EPA 

electronically for early EPA comments. 

Electronic submittal will also facilitate, 

expedite and promote national 

consistency in the EPA’s review of state 

plans and promote transparency by 

providing stakeholder-specific access to 

updated information on state plan status 

and posting of plan requirements for 

viewing by the public, government 

regulators and regulated entities. The 

EPA recently implemented an electronic 

submittal process for SIPs under CAA 

section 110 and continues to explore 

opportunities to increase the ease and 

efficiency with which states and the 

regulated community can meet 

regulatory data submittal requirements. 

In summary, the EPA believes electronic 

submittal will be enormously beneficial 

in terms of improving coordination and 

cooperation between the EPA and its 

state partners in developing approvable 

state plans. We note, however, that there 

may be some circumstances where 

having paper copies of the plan is 

needed to facilitate public engagement, 

and encourage states to take those 

considerations into account. 

d. Plan templates. 

In the proposal, the EPA requested 

comment on the creation of templates 

for initial submittals and final state plan 

submittals. Multiple commenters 

requested the EPA provide state plan 

templates. One commenter requested 

templates for different plan designs (e.g. 

a mass-based trading framework, a ratebased trading framework, multi-state 

compliance and a utility-based portfolio 

approach) and for specific plan 

components (e.g. how to incorporate a 

state RE standard and an EE program 

into a state plan, how to assess the 

emission reductions delivered by RE 

and EE). The EPA has determined that 

the broad range of approaches states 

may take in preparing individual or 

multi-state plans makes the 


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847Under this grant of authority to prescribe 

shorter deadlines, the EPA has in a number of 

occasions required SIPs to be submitted in 1 year. 

development of specific templates 

challenging and likely not useful to 

states. However, concurrent with this 

final rule, the EPA is proposing model 

rules for both rate- and mass-based 

programs in conjunction with the 

proposed federal plan. These effectively 

can serve as a template for states when 

preparing their state plan submittals. 

The EPA will continue extensive 

outreach to states and work closely with 

them on the need for additional tools 

and guidance to facilitate the 

development of approvable state plans. 

9. Legal Basis Regarding State Plan 

Process 

CAA section 111(d)(1) requires the 

EPA to promulgate procedures ‘‘similar’’ 

to those in section 110 under which 

states adopt and submit CAA section 

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 CAA 

section 111(d) state plans, and if so, 

precisely how those procedures should 

apply. The EPA is proposing these 

revisions to the CAA section 111(d) 

implementing regulations in the notice 

of proposed rulemaking for the federal 

plan being issued concurrently with this 

final rule. In this section we discuss the 

legal basis for procedures that the EPA 

is finalizing in this action: Initial 

submittals, extensions, and plan 

revisions. 

First, by using the ambiguous word 

‘‘similar,’’ Congress delegated authority 

to the EPA to determine precisely what 

procedures would govern 111(d) plans. 

‘‘Similar’’ does not have an identical 

meaning as the word ‘‘same.’’ One 

definition of ‘‘similar’’ is ‘‘having 

likeness or resemblance, especially in a 

general way.’’ The American College 

Dictionary 1127 (C.L. Barnhart, ed. 

1970). On the other hand, ‘‘same’’ is 

defined as ‘‘alike in kind, degree, 

quality; that is, identical’’ or 

‘‘unchanged in character.’’ Id. at 1073. 

Had Congress intended that the 

procedures for section 111(d) plans be 

indistinguishable from those in section 

110, Congress knew how to say so. See, 

e.g., 36 U.S.C. 2352(b)(2)(B) (‘‘same 

procedures’’). And had Congress 

intended that the procedures for section 

111(d) plans be as close as possible to 

those in section 110, Congress knew 

how to say that. See, e.g., 38 U.S.C. 

4325(c) (agency ‘‘shall ensure, to the 

maximum extent practicable, that the 

procedures are similar to’’ certain other 

procedures). Therefore, Congress must 

have intended to give the EPA leeway 

to create procedures for section 111(d) 

state plans that somewhat vary from 

those in section 110, so long as the 

section 111(d) procedures are 

reasonably tied to the purpose and text 

of section 111(d). In other words, 

‘‘similar’’ creates a gap in the statute 

that the EPA may reasonably fill. 

a. Initial submittals and extensions. 

Initial submittals in this instance are 

a reasonable gap-filling procedural step. 

As explained in our proposal, certain 

aspects of section 111(d) plan 

development for these particular 

guidelines warrant our creation of this 

procedural step, even though section 

110 does not provide for initial 

submittals. As explained above, though, 

we are not bound under section 

111(d)(1) to follow exactly the same 

procedures. 

With respect to the timing of initial 

submittals, final submittals, and 

extensions, we note that section 111 

does not prescribe any particular 

deadlines, instead leaving it to EPA’s 

discretion to establish ‘‘similar’’ 

procedures to section 110. The 

implementing regulations for section 

111(d) plans require state plans to be 

submitted within 9 months of 

finalization of emission guidelines. 

Section 110(a)(1) provides that states 

should adopt and submit SIPs that 

provide for implementation, 

maintenance, and enforcement of the 

NAAQS within 3 years, or such shorter 

period as the Administrator may 

prescribe.847 As further explained in 

Section VIII.E., the EPA is providing 

states with up to 3 years to submit a 

final plan under this rule, contingent 

upon the grant of an extension through 

an initial submittal due by September 6, 

2016. Section 110(a)(1) does not provide 

any particular factors for the 

Administrator to consider in prescribing 

a shorter period. Thus, the EPA’s 

prescription of a shorter period for 

either an initial submittal or a final plan 

submittal is consistent with the 

discretion granted in section 110(a)(1). 

We further discuss why the September 

6, 2016 initial submittal deadline is 

reasonable in Section VIII.E., and such 

deadline is achievable by states seeking 

to submit a final plan within 3 years. 

We also note that section 110(b) 

provides for extensions of 2 years for 

plans to implement secondary NAAQS, 

that other provisions in part D provide 

for extensions of due dates of attainment 

plans in certain circumstances, and that 

the section 111(d) implementing 

regulations provide for extensions 

generally. We conclude, in view of the 

above discussion of ‘‘similar,’’ that the 

approach of initial submittals and 

extensions of due dates as proposed are 

reasonable procedures that, while not 

identical to the procedures in section 

110, are still similar. 

Some commenters argued that the 1- 

year period for initial submittals and, 

even assuming an extension, the 

additional 1- to 2-year period for final 

submittals were unreasonably short, 

particularly in light of the possibility 

that some state legislatures might need 

to act to provide adequate legal 

authority for these particular plans. We 

are not finalizing the 1-year extension 

for single state submittals, and we have 

addressed concerns about legal 

authority for the initial submittals by 

allowing states to identify remaining 

legislative action in those submittals. 

With respect to the overall period of 

up to 3 years for submittals, we 

continue to find it reasonable and 

consistent with other deadlines in the 

CAA. First, section 110(a)(1) requires 

states to submit a plan for 

implementation, maintenance, and 

enforcement of new NAAQS within 3 

years of promulgation of that NAAQS. 

This is true even if the EPA promulgates 

a NAAQS for a previously non-criteria 

pollutant. In that case, it is possible and 

even likely that at least some state 

agencies will lack statutory authority to 

regulate the new pollutant. Nonetheless, 

Congress dictated that states should 

submit section 110(a)(1) plans within 3 

years. 

Furthermore, we note that under 

subpart 1 of Part D of Title 1, attainment 

plans are generally due no later than 3 

years after designation of a 

nonattainment area, and under other 

subparts of Part D, plans are due even 

more quickly. For example, under 

subpart 4, attainment plans for 

particulate matter are generally due 18 

months after designation, and under 

subpart 5, the same deadline applies for 

attainment plans for sulfur oxides, 

nitrogen dioxide and lead. Developing 

attainment plans may or may not 

require states to seek additional 

legislative authority, but certainly in 

terms of complexity they are similar to 

section 111(d) plans for this guideline. 

In general, attainment plans must 

contain (among other things) a 

comprehensive inventory of sources of 

the relevant pollutant and its precursors 

(which in populated areas can be very 

numerous), control measures for those 

sources (including individualized 

control measures for the larger sources), 

and modeled demonstrations of 


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attainment (which in some instances 

requires photochemical grid modeling). 

Thus, it is reasonable to have the same 

timeline for these section 111(d) plans 

as Congress generally provided for 

attainment plans in section 172(b). 

b. State plan modifications. 

Section 110(l) provides for states to 

revise their SIPs, as does 40 CFR 60.28 

for section 111(d) plans. Section 110(l) 

also sets out a standard for revisions: It 

prohibits the EPA from approving a SIP 

revision that would interfere with any 

applicable requirement concerning 

attainment or reasonable further 

progress, or any other applicable 

requirement of the CAA. Under the 

existing section 111(d) implementing 

regulations, the Administrator will 

disapprove section 111(d) plan revisions 

as unsatisfactory when they do not meet 

the requirements of subpart B to part 60. 

See 40 CFR 60.27(c)(3). However, the 

implementing regulations do not set 

forth a substantive standard like that in 

section 110(l). 

Section 111(d)(1) does not mention 

revisions (except indirectly through the 

reference to section 110) and, therefore, 

does not explicitly provide any 

substantive requirements for them. 

There is, therefore, a gap in the statute 

that the EPA may reasonably fill, since 

many stakeholders commented on the 

desirability of states being able to 

modify their plans, and the EPA agrees. 

It is reasonable, at a minimum, that the 

state plan as revised should continue to 

provide for implementation and 

enforcement of the standards of 

performance, and to achieve the CO2

emission performance rates or state CO2

emission performance goal. This is 

analogous to the substantive 

requirements of section 110(l), which as 

explained above for section 110(a)(2), 

we may consider in determining how to 

reasonably fill statutory gaps for section 

111(d) plans. 

In our proposal, we stated that certain 

revisions to state plans under these 

emission guidelines, those that revised 

enforceable measures for affected EGUs, 

should satisfy some additional 

conditions. First, the state should 

demonstrate that the plan continues to 

achieve the CO2 emission performance 

rates or state CO2 emission performance 

goal. We proposed that this 

demonstration might be simple for 

minor revisions, but for major revisions 

a more complete demonstration may be 

required. We are finalizing this 

proposal. As legal basis for this position, 

we note that a demonstration is 

necessary to show that a state plan 

provides for implementation of 

standards of performance that achieve 

the CO2 emission performance rates or 

state CO2 emission performance goal, 

and as explained above we can 

reasonably require the same of 

revisions. 

It is also reasonable to tailor the 

requirements of the demonstration to 

the magnitude of the revision. The EPA 

has taken a similar approach to tailoring 

the requirements for a technical 

demonstration that, under section 

110(l), a SIP revision does not interfere 

with any applicable requirement 

concerning attainment of the NAAQS. If 

a SIP revision does not relax the 

stringency of any SIP measure, then the 

demonstration is simple. If the SIP 

revision does relax the stringency of SIP 

measures, then a qualitative or 

quantitative analysis may be necessary 

to show non-interference, depending on 

the nature of the revision, the current air 

quality in the area, and other factors. 

Finally, we proposed that revisions 

‘‘should not result in reducing the 

required emission performance for 

affected EGUs specified in the original 

approved plan. In other words, no 

‘backsliding’ on overall plan emission 

performance through a plan 

modification would be allowed.’’ 79 FR 

34917/1. We received adverse 

comments that this standard did not 

have a basis in section 111(d). 

According to commenters, since the 

standard for EPA approval of a section 

111(d) plan is whether the plan is 

satisfactory in establishing and 

providing for implementation and 

enforcement of standards of 

performance that achieve the emission 

performance rates or goal, the same 

standard should apply to revisions. In 

other words, the standard for revisions 

should be whether the plan as revised 

is satisfactory. We believe that our 

proposal was unclear as to this point, 

and we agree that the 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; consequences if the 

CO2 emission performance rates or state 

CO2 emission goals are not met; and outyear requirements. 

1. Compliance Periods, Monitoring and 

Reporting Requirements for Affected 

EGUs 

For plans that include emission 

standards on affected EGUs, the EGU 

emission standards for the interim 

period must have schedules of 

compliance for each interim step 1, 2 

and 3 for the calendar years 2022–2024, 

2025–2027 and 2028–2029, respectively. 

For the final period, EGUs must have 

emission standards that have schedules 

of compliance for each 2 calendar years 

starting in 2030 (i.e., 2030–2031, 2032– 

2033, 2034–2035, etc.). If a backstop is 

triggered for a state measures plan, the 

schedule of compliance for the federally 

enforceable emission standards must 

begin no later than 18 months after the 

backstop is triggered and end at the end 

of the same compliance period. For 

example, if a backstop is triggered on 

July 1, 2025, the compliance period for 

the backstop emission standards must 

begin no later than January 1, 2027, and 

end on December 31, 2027. The next 

compliance period for the backstop 

emission standards would be January 1, 

2028–December 31, 2029. 

In the June 2014 proposal, the EPA 

proposed that the appropriate averaging 

time for any rate-based emission 

standard 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 ratebased plan should be different from a 

mass-based plan. Comments stated that 

a multi-year averaging period is 

appropriate for rate-based and massbased plans to account for variations 

that can occur in a single year, allowing 

operators the flexibility they need to 

manage unforeseen events. The 

commenters also recommended that the 

final rule use discrete 3-year periods for 

compliance reconciliation instead of the 

rolling-average approach proposed. 

The EPA has considered all comments 

received on this matter and is finalizing 

the compliance periods specified above, 

which respond to the comments by 

applying to both rate- and mass-based 

programs, providing compliance periods 

longer than 1 year, and establishing 

block compliance periods rather than a 

rolling average approach. We agree with 

comments that longer averaging periods 

allow for operational and seasonal 

variability to even out. The EPA 

finalizes that states can choose to set 

shorter compliance periods for their 

emission standards but none that are 

longer than the compliance periods the 

EPA is finalizing in 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 


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conflicts. The EPA recognizes that the 

compliance periods provided for in this 

rulemaking are longer than those 

historically and typically specified in 

CAA rulemakings. ‘‘The time over 

which [the compliance standards] 

extend should be as short term as 

possible and should generally not 

exceed one month.’’ See e.g., June 13, 

1989 ‘‘Guidance on Limiting Potential to 

Emit in New Source Permitting’’ and 

January 25, 1995 ‘‘Guidance on 

Enforceability Requirements for 

Limiting Potential to Emit through SIP 

and § 112 Rules and General Permits.’’ 

However, the EPA has determined that 

the longer compliance periods provided 

for in this rulemaking are acceptable in 

the context of this specific rulemaking 

because of the unique characteristics of 

this rulemaking, including that CO2 is 

long-lived in the atmosphere, and this 

rulemaking is focused on performance 

standards related to those long-term 

impacts. The distinction between these 

unique characteristics and the EPA’s 

general practice regarding compliance 

periods is bolstered by the EPA 

guidance on appropriate averaging 

periods for emission limitations in 

NAAQS implementation. For example, 

the EPA guidance has stated that in 

implementation of the ozone standards, 

which have a short averaging period, the 

averaging period for VOC emission 

limitations should be correspondingly 

short. See 51 FR 43857. A longer 

averaging period for VOC emission 

limitations (VOCs are one of the key 

precursors to ozone formation) can 

allow spikes in emissions that adversely 

impact ambient air and violate the short 

term ozone standards. This is precisely 

the opposite of the unique 

characteristics cited above: the longlived persistence of CO2 in the 

stratosphere and the intent of these 

guidelines to address the long-term 

impacts. 

State plans must contain requirements 

for tracking and reporting actual plan 

performance during implementation, 

which includes reporting of CO2

emissions from affected EGUs. Affected 

EGUs must comply with emissions 

monitoring and reporting requirements 

that are largely incorporated from 40 

CFR part 75 monitoring and reporting 

requirements. The majority of affected 

EGUs are already familiar with the 

reporting requirements of part 75, and 

because of this, the EPA has chosen to 

streamline the applicable reporting 

requirements for affected EGUs under 

the state plans in the final rule. States 

must require all affected EGUs to 

monitor and report hourly CO2

emissions and net energy output 

(including total net MWh output that is 

comprised of generation, and where 

applicable, useful thermal output 

converted to net MWhs) on a quarterly 

basis in accordance with 40 CFR part 

75. Note that this requirement applies 

for all types of state plans, regardless of 

whether the state chooses the option of 

the CO2 emission performance rates, a 

state rate-based CO2 emission goal, or a 

state mass-based CO2 emission goal. 

In the June 2014 proposal, the EPA 

proposed that state plans must include 

monitoring, reporting and 

recordkeeping requirements for useful 

energy output from affected EGUs. 

Multiple commenters questioned 

whether gross rather than net electrical 

production should be reported by 

affected EGUs and recommended that 

the EPA should utilize gross rather than 

net generation. Many commenters 

recommended electricity be reported in 

the form used in the 111(b) rules for 

consistency between reporting 

requirements and simplification of 

calculation of emission limitations 

between new and old sources. 

Commenters also stated that to the 

extent the EPA seeks to provide 

guidance to states regarding its preferred 

monitoring and reporting procedures, 

the EPA should encourage states to 

avoid imposing additional monitoring 

and reporting burdens by taking 

advantage of the monitoring 

requirements that already exist to the 

greatest extent possible. For example, 

the commenters noted that the 40 CFR 

part 75 monitoring procedures used to 

comply with other programs, such as 

the Title IV Acid Rain Program, provide 

much of the data that would be needed 

to demonstrate compliance under the 

rule. Comments stated that the June 

2014 proposal appeared to mandate a 

monitoring approach that would 

eliminate key flexibilities provided in 

the part 75 regulations, thus requiring 

utilities to maintain separate document 

collection and reporting procedures and 

potentially eliminating important 

alternative monitoring options intended 

to ensure representative, cost-effective 

monitoring approaches are available. 

The commenters asked the EPA to 

revise its proposal to make clear that the 

procedures established under part 75 

will suffice or explain the need for any 

exceptions. Commenters indicated that 

the rule should require all affected 

EGUs to monitor CO2 emissions and net 

hourly electric output under 40 CFR 

part 75, and report the data using the 

EPA’s Emission Collection and 

Monitoring Plan System (ECMPS) 

assuring a more uniform monitoring and 

reporting process for all EGUs. The EPA 

believes that the final monitoring and 

reporting requirements (via ECMPS) 

address the issue of duplicative 

requirements and alleviate concern 

about lost flexibility raised by 

commenters. 

2. Plan Performance Demonstrations 

The state plan must include emission 

performance checks, and for state 

measures plans, periodic program 

implementation milestones. The state 

plan must provide for tracking of 

emission performance, and for measures 

to be implemented if the emission 

performance of affected EGUs in the 

state does not meet the applicable CO2

emission performance rates or state CO2

emission goal during a performance 

period. 

As discussed above in section VII, the 

agency is finalizing CO2 emission 

performance rates or state-specific CO2

emission goals that represent emission 

levels to be achieved by 2030 and 

emission levels to be achieved over the 

2022–2029 interim period, and over 

three interim steps of 2022–2024, 2025– 

2027 and 2028–2029. A state may 

choose to define different interim step 

emission levels for achieving its 

required 2022–2029 average 

performance rate. The EPA recognizes 

the importance of ensuring that, during 

the 8-year interim period (2022–2029) 

for the interim performance rates or 

interim state goal, a state is making 

steady progress toward achieving the 

required level of emission performance. 

For both emission standards plans and 

state measures plans, the final rule 

requires periodic checks on overall 

emission performance leading to 

corrective measures or implementation 

of the backstop, if necessary, as 

described in section VIII.F.3 below. 

States must demonstrate that the interim 

steps were achieved at the end of the 

first two interim step periods. 

In 2032 and every 2 years thereafter, 

states must demonstrate that affected 

EGUs achieved the final performance 

rates or state goal on average or 

cumulatively, as appropriate, during 

each 2-year reporting period (i.e., 2030– 

31, 2032–33, 2034–2035 etc.). The 

multi-year performance periods for 

measuring actual plan performance 

against the performance rates 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 


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848For EGUs that produce both electric energy 

output and other useful energy output, there would 

also be a credit for non-electric output, expressed 

in MWh. 

849Emission budget trading programs in such 

plans establish CO2 emission budgets equal to or 

less than the state mass CO2 goal, as specified for 

the interim plan performance period (including 

specified levels in interim steps 1 through 3) and 

the final 2-year plan performance periods. 

energy output 848 from affected EGUs 

over the reporting period, with rate 

adjustments for qualifying measures, 

such as RE and demand-side EE 

measures. For a mass-based plan, 

emission performance is total tons of 

CO2 emitted by affected EGUs over the 

reporting period. 

For emission standards plans, as 

discussed in section VIII.D, the state 

must submit a report to the EPA 

containing the emissions performance 

comparison for each reporting period no 

later than the July 1 following the end 

of each reporting period (i.e., by July 1, 

2025; July 1, 2028; July 1, 2030; July 1, 

2032; and so on). As discussed in 

section VIII.D, the emission comparison 

required in the July 1, 2030 report must 

compare the actual emissions from 

affected EGUs over the interim period 

(2022–2029) with the interim CO2

emission performance rates or state CO2

emission goal. The report is not required 

to include a comparison for the interim 

step 3 period, but must include the 

actual emissions from affected EGUs 

during the interim step 3 period. 

The EPA notes that for certain types 

of emission standards plans, with massbased emission standards in the form of 

an emission budget trading program, 

achievement of a state’s mass-based CO2

goal (including interim step goals and 

final goal) will be assessed by the EPA 

based on compliance by affected EGUs 

with their emission standards under the 

program, rather than CO2 emissions 

during a specific interim step period or 

final period. This approach is limited to 

plans with emission budget trading 

programs where compliance by affected 

EGUs with the emission standards will 

ensure that, on a cumulative basis, the 

state interim and final mass-based CO2

goals are achieved.849 This approach 

allows for CO2 allowance banking across 

plan performance periods, including 

from the interim period to the final 

period. As a result, CO2 emissions by 

affected EGUs could differ from the state 

mass-based CO2 goal during an 

individual plan performance period, but 

on a cumulative basis CO2 emissions 

from affected EGUs would not exceed 

what is allowable if the interim and 

final CO2 goals are achieved. 

Also as discussed in section VIII.D, 

states that choose a state measures plan 

must submit an annual report no later 

than July 1 following the end of each 

calendar year in the interim period. This 

annual report must include the status of 

the implementation of programmatic 

state measures milestones identified in 

the state plan submittal. The annual 

report that follows the end of each 

reporting period (i.e., 2022–2024, 2025– 

2027, and 2028–2029) must also include 

an emissions performance comparison 

for the reporting period, as described 

above for the emission standards plan. 

As discussed in section VIII.D, the 

emission comparison required in the 

July 1, 2030 report must compare the 

actual emissions from affected EGUs 

over the interim period (2022–2029) 

with the interim CO2 emission 

performance rates or state CO2 emission 

goal. The report is not required to 

include a comparison for the interim 

step 3 period, but must include the 

actual emissions from affected EGUs 

during the interim step 3 period. 

Beginning with the final period of 2030 

and onward, states using a state 

measures plan must submit a biennial 

report no later than July 1 following the 

end of each reporting period with an 

emission performance comparison for 

each reporting period, consistent with 

the reporting requirements for emission 

standards plans. 

In the June 2014 proposal, the EPA 

proposed that a state report is due to the 

EPA no later than July 1 of the year 

immediately following the end of each 

reporting period. The EPA requested 

comment on the appropriate frequency 

of reporting of the different proposed 

reporting elements, considering both the 

goals of minimizing unnecessary 

burdens on states and ensuring program 

effectiveness. In particular, the agency 

requested comment on whether full 

reports containing all of the elements 

should only be required every 2 years 

rather than annually and whether these 

reports should be submitted 

electronically, to streamline 

transmission. 

The EPA mainly received adverse 

comments for requiring annual state 

reporting; commenters stated that this 

requirement was too burdensome for 

both states and the EPA. Commenters 

also requested that the EPA extend the 

due date of the annual report from July 

1 to at least December 31. Commenters 

stated that because of the timing of 

current data collection and the need to 

leave time to organize and submit the 

reports, allowing only 6 months after 

the close of the year is problematic. 

Commenters asked that the EPA 

consider reducing the amount of data 

required if annual reporting was 

required. 

Considering the comments received 

and the goals of minimizing 

unnecessary burdens on states and 

ensuring program effectiveness, the EPA 

has reduced the frequency of reporting 

of emissions data to every 3 years for the 

first two interim steps and every 2 years 

thereafter. However, the EPA is 

finalizing that state reports are due to 

the EPA no later than July 1 following 

the end of each reporting period. The 

EPA believes states can design their 

state plans to receive the data and 

information needed for these reports in 

a timely manner so that this 

requirement can be met. Furthermore, 

some of the state reporting 

requirements, such as reporting of EGU 

emissions, can be met through existing 

reporting mechanisms (ECMPS) and 

would not place additional burdens on 

states. 

3. Consequences if Actual Emission 

Performance Does Not Meet the CO2

Emission Performance Rates or State 

CO2 Emission Goal 

The EPA recognizes that, under 

certain scenarios, an approved state 

plan might fail to achieve a level of 

emission performance that meets the 

emission guidelines or the level of 

performance established in a state plan 

for an interim milestone. Despite 

successful implementation of certain 

types of plans, emissions under the plan 

could turn out to be higher than 

projected at the time of plan approval 

because actual conditions vary from 

assumptions used when projecting 

emission performance. Emissions also 

could theoretically exceed projections 

because affected entities under a state 

plan did not fulfill their responsibilities, 

or because the state did not fulfill its 

responsibilities. 

The final rule specifies the 

consequences in the event that actual 

emission performance under a state plan 

does not meet, or is not on track to meet, 

the applicable interim and interim step 

CO2 emission performance rates or state 

goals in 2022–2029, or does not meet 

the applicable final CO2 emission 

performance rates or state CO2 emission 

goal in 2030–2031 or later. The 

determination that a state is not on track 

to meet the applicable interim goal or 

interim step goals in 2022–2029 or the 

applicable final goal in 2030–2031 or 

later, or the CO2 emission performance 

rates, will be made through the actual 

performance checks to be included in 

state reports of performance data 

described in section VIII.D.2.a above. 

For emission standards plans, the 

final rule specifies that corrective 

measures must be enacted once 

triggered. Corrective measures apply 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64867 

850To be specific, corrective measures 

requirements apply to all emission standard plan 

designs that do not mathematically assure that the 

plan performance level will be achieved when all 

affected EGUs are in compliance with their 

emission standards, regardless of electricity 

production and electricity mix. Corrective measures 

requirements apply, for example, to emission 

standards plans that include standards on affected 

EGUs that differ from the emission performance 

rates in the guidelines. Backstop requirements 

apply to state measures plans. 

851The EPA notes that as part of the proposed 

federal plan rulemaking, it is proposing a regulatory 

mechanism to call plans in the instances of 

substantial inadequacy to meet applicable 

requirements or failure to implement an approved 

plan. 

852As explained in section VIII.C.3.b., state 

measures plans must require the backstop to take 

effect if actual CO2 emission performance fails to 

meet the level of emission performance specified in 

the plan over the 8-year interim performance period 

(2022–2029), or for any 2-year final goal 

performance period. The plan also must require the 

backstop to take effect if actual emission 

performance is deficient by 10 percent or more 

relative to the performance levels that the state has 

chosen to specify in its plan for the interim step 1 

period (2022–2024) or the interim step 2 period 

(2025–2027). 

853The EPA notes that as part of the proposed 

federal plan rulemaking, it is proposing a regulatory 

mechanism to call plans in the instances of 

substantial inadequacy to meet applicable 

requirements or failure to implement an approved 

plan. 

only to emission standard plans in 

which full compliance by affected EGUs 

would not necessarily lead to 

achievement of the emission 

performance rates or CO2 emission 

goals.850 For such plans, corrective 

measures are triggered if actual CO2

emission performance by affected EGUs 

is deficient by 10 percent or more 

relative to the specified level of 

emission performance in the state plan 

for the step 1 or step 2 interim 

performance periods. Corrective 

measures also are triggered if actual 

emission performance fails to meet the 

specified level in the plan for the 8-year 

interim period 2022–2029, or for any 2- 

year final goal performance period 

(beginning in 2030). In such cases, the 

state report must include a notification 

to the EPA that corrective measures 

have been triggered. If, in the event of 

such an exceedance, the EPA 

determines that corrective measures 

have been triggered and the state has 

failed to notify the EPA, the EPA will 

inform the affected EGUs that corrective 

measures have been triggered.851

When corrective measures are 

triggered, if the state plan does not 

already contain corrective measures, the 

state must submit to the EPA a plan 

revision including corrective measures 

that adjust requirements or add new 

measures. The corrective measures must 

both ensure future achievement of the 

CO2 emission performance rates or state 

CO2 emission goal and achieve 

additional emission reductions to offset 

any emission performance shortfall that 

occurred during a performance period. 

The shortfall must be made up as 

expeditiously as practicable. The state 

plan revision submission must explain 

how the corrective measures both make 

up for the shortfall and address the state 

plan deficiency that caused the 

shortfall. The state must submit the 

revised plan to the EPA as expeditiously 

as practicable and within 24 months 

after submitting the state report 

indicating the exceedance. The 24- 

month time period allows time to 

identify corrective measures and make 

rule changes through state regulatory 

processes. The EPA will then act on the 

plan revision within 12 months, 

consistent with other plan revisions and 

with the timing for final plan submittals 

originally submitted by states. The state 

must implement corrective measures 

within 6 months of the EPA’s approval 

of a plan revision adding them. 

For states using the state measures 

approach, the EPA is finalizing the 

backstop requirement as described in 

section VIII.C.3 of this preamble. As 

discussed in section VIII.D.2, the 

determination that a state using the state 

measures approach is not on track to 

meet the applicable interim goal or 

interim step goals in 2022–2029, or the 

applicable final goal in 2030–2031 or 

later, is based on checks that must be 

included in state reports that must be 

submitted annually during the interim 

period and biennially during the final 

period. The state must annually report 

on its progress in meeting its 

programmatic state measures milestones 

during the interim period. In addition, 

the state must report actual emission 

performance checks, similar to the 

requirements discussed above for 

emission standards plans, in 2025, 2028, 

2030, and every 2 years thereafter. If, at 

the time of the state report to the EPA, 

the state did not meet the programmatic 

state measures milestones for the 

reporting period, or the performance 

check shows that the plan’s actual CO2

emission performance warrants 

implementation of backstop 

requirements,852 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.853

For multi-state plans, corrective 

measure or backstop provisions would 

be required for the same plan 

approaches for which those provisions 

are required in individual state plans. 

For multi-state plans using plan 

approaches to which corrective 

measures or backstop requirements 

apply, all states that are party to the 

multi-state plan would be subject to 

corrective action or backstop 

requirements, and requirements to make 

up the past CO2 emission performance 

shortfall, if those requirements were 

triggered. This is because multi-state 

plans are joint plans (even if created 

through separate state submittals). That 

would not be the case for coordinated 

individual state plans linked through 

interstate ERC or emission allowance 

trading. In the case of coordinated 

individual state plans, for plan types 

subject to corrective measure or 

backstop requirements, the state where 

the CO2 emission performance 

deficiency occurs would be required to 

implement corrective measures or 

backstop requirements for affected 

EGUs, as applicable, and remedy the 

past CO2 emission performance 

shortfall. 

Multiple commenters requested that 

corrective measures not be required in 

the case of a catastrophic, 

uncontrollable event. We recognize that 

there are potential system emergencies 

that cannot be anticipated that could 

cause a severe stress on the electricity 

system for a length of time such that the 

multi-year requirements in a state plan 

may not be achievable by certain 

affected EGUs without posing an 

otherwise unmanageable risk to 

reliability. We are finalizing a reliability 

safety valve, which includes an initial 

period of up to 90 days during which a 

reliability-critical affected EGU or EGUs 

will not be required to meet the 

emission standard established for it 

under the state plan but rather will meet 

an alternative standard. While the initial 

90-day period is in use, the emissions of 

the affected EGU or EGUs that exceed 

their obligations under the approved 

state plan will not be counted against 

the state’s overall goal or emission 

performance rate for affected EGUs and 

will not be counted as an exceedance 

that would otherwise trigger corrective 

measures under an emission standard 

plan type or an exceedance that would 

trigger a backstop under a state 

measures plan type. Use of the 

reliability safety valve will not alter or 

abrogate any other obligations under the 

approved state plan. After the initial 

period of up to 90 days, the reliabilitycritical affected EGU is required to 

continue to operate under the original 

state plan emission standard or an 

alternative standard as part of the 


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854Similar considerations apply to the 

requirement under the state measures approach to 

revise the plan to make up the shortfall. 

reliability safety valve, and the state 

must revise its plan to accommodate 

changes needed to respond to ongoing 

reliability requirements and to ensure 

than any emissions excess of the 

applicable state goals or performance 

rates occurring after the initial period of 

up to 90 days are accounted for and 

offset. See section VIII.G.2.e of this 

preamble. 

Multiple commenters supported the 

inclusion of strong enforcement 

measures for ensuring the interim and 

final goals are met, including the 

required use of corrective measures 

when triggered. Other commenters 

provided feedback as to the percentage 

that actual emission performance would 

need to exceed the level of emission 

performance specified in the statewide 

plan to trigger corrective measures. 

Some commenters supported the trigger 

that we are finalizing (actual emissions 

or emission rate performance that is 10 

percent or more than the specified level 

of emission performance in the state 

plan for the interim step 1 or step 2 

performance periods), while some 

recommended a lower or higher trigger. 

The agency is finalizing the trigger at 

the level of 10 percent for the interim 

step 1 or step 2 performance periods. 

Ten percent is a reasonable level to 

ensure that when deficiencies in state 

plan performance begin to emerge, 

corrective measures (or backstop 

requirements) will be implemented 

promptly to avoid emissions shortfalls 

(or minimize the extent of shortfalls) 

relative to the 8-year interim goal and 

the final goal, which reflect the BSER. 

The 10 percent figure also provides 

latitude for a state’s emission 

improvement trajectory during the 

interim period to deviate a bit from its 

planned path without triggering these 

requirements, as the state initiates or 

ramps up programs to meet the 8-year 

interim goal and final goal. 

The EPA requested comment on 

whether the agency should promulgate 

a mechanism under CAA section 111(d) 

similar to the SIP call mechanism in 

CAA section 110. Under this approach, 

after the agency makes a finding of the 

plan’s failure to achieve the CO2

emission performance rates or state CO2

emission goal during a performance 

period, the EPA would require the state 

to cure the deficiency with a new plan 

within a specified period of time. If the 

state still lacked an approved plan by 

the end of that time period, the EPA 

would have the authority to promulgate 

a federal plan under CAA section 

111(d)(2)(A). 79 FR 34830, 34908/1–2 

(June 18, 2014). 

The EPA intends that planned 

revisions to the part 60 implementing 

regulations will clarify (among other 

things) whether the EPA has authority 

to call for plan revisions under section 

111(d) when a state’s plan is not 

complying with the requirements of this 

guideline, and if so, precisely what 

procedures should apply. The EPA is 

proposing these revisions to the 111(d) 

implementing regulations in the notice 

of proposed rulemaking for the federal 

plan. The EPA is not taking final action 

now on this issue or the related change 

to the implementing regulations. 

a. Legal basis for corrective measures. 

The EPA discussed the concept of 

corrective measures in our 1992 General 

Preamble for the Implementation of 

Title I of the CAA Amendments of 1990. 

57 FR 13498 (Apr. 16, 1992). The 

General Preamble sets out four general 

principles that apply to all SIPs, 

‘‘including those involving emissions 

trading, marketable permits and 

allowances.’’ Id. at 13568. The fourth 

principle, accountability, means (among 

other things) that ‘‘the SIP must contain 

means . . . to track emission changes at 

sources and provide for corrective 

action if emissions reductions are not 

achieved according to the plan.’’ In the 

General Preamble, we noted that Part D 

of Title I explicitly provided for this in 

certain instances by requiring 

milestones and contingency measures. 

Some commenters noted that the 

contingency measures explicitly 

required by part D are required to be 

adopted in the attainment plan and 

ready to implement when a milestone is 

not achieved or the area fails to attain 

the relevant NAAQS. These commenters 

therefore concluded that corrective 

measures for 111(d) plans should 

likewise already be adopted in the 

111(d) plan and ready to implement. We 

disagree. Under Part D, contingency 

measures are not expected to fully bring 

the area into attainment. In fact, this 

would not be possible given the 

difficulty of predicting in advance 

exactly what measures would be needed 

to fully attain. A better analogue in Part 

D for the corrective measures in these 

guidelines is the primary way Part D 

addresses failure to attain: The state is 

required to revise its plan in various 

ways within a certain time in order to 

bring about attainment. See, e.g., section 

179(d). This is analogous to what we are 

requiring for corrective measures. Thus, 

part D contingency measures are unlike 

the corrective measures in this rule. 

However, the requirement to revise an 

attainment plan in response to failure to 

attain differs somewhat from the 

corrective measures in these guidelines. 

Under these guidelines, the corrective 

measures must make up the difference 

by which the plan fell short of the goal, 

including any prior shortfall that had 

accumulated if the plan fell short of the 

goal in prior years. There is no 

corresponding requirement in 

attainment planning to increase the 

stringency of the plan by an amount that 

somehow makes up for any shortfall in 

attainment from prior years; instead the 

revised plan must demonstrate 

attainment going forward, and other 

more stringent requirements (such as 

requirements for best available control 

measures) may be triggered. 

This distinction is the natural result 

of the difference between these 

guidelines and NAAQS attainment 

planning. In this case, we are finalizing 

guidelines representing technologybased standards for a pollutant with 

cumulative and long-lasting effects. If a 

plan falls short of a performance goal, 

then in effect the standards of 

performance in the plan have failed to 

reflect the BSER over the corresponding 

period. Due to the cumulative effects of 

CO2, it is possible to remedy this failure 

by requiring the plan to be revised in 

such a way that the standards of 

performance in the revised plan will 

reflect the BSER over the cumulative 

plan period, and this can be done by 

requiring the revised plan to make up 

the shortfall from the previous period. 

In short, the flexibility that these 

guidelines provide should not come at 

the cost of allowing the standards of 

performance to reflect less than the 

BSER over the long run.854

Some commenters noted that 111(d) 

does not contain explicit provisions 

regarding corrective measures, and they 

therefore inferred that the EPA is not 

authorized to require them. That 

inference is mistaken. The requirement 

for 111(d) plans to ‘‘provide for 

implementation and enforcement’’ of 

the standards of performance is 

ambiguous and does not directly speak 

to whether corrective measures should 

or should not be required. There is 

therefore a gap for the EPA to fill. While 

the discussion above about Part D does 

not independently provide any 

authority to fill this gap, the fact that 

Congress created a scheme with stages 

of planning in Part D suggests that it 

would be reasonable, if appropriate, to 

fill this gap in 111(d) in a similar way. 

In this guideline, it is appropriate for 

emission standards plans to fill this gap 

with corrective measures if triggered. 

There are two ways an emission 

standards plan can provide for 

implementation of standards of 

performance that achieve the CO2


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emission performance rates or requisite 

state CO2 emission performance goal. 

First, the state can set emission 

standards that necessarily achieve the 

performance rates or goal, even if the 

affected EGUs in the future vary in their 

relative amounts of electricity 

generated. Second, the state can set 

emission standards that are 

demonstrated to achieve the 

performance rates or goal based on 

assumptions about the relative amounts 

of electricity generated, but which may 

turn out to not actually achieve the goal 

even if all affected EGUs comply. This 

is analogous to an attainment plan that 

demonstrated attainment by the 

applicable attainment date, but due to 

unpredicted economic changes actually 

failed to attain. In this second case, the 

EPA interprets the ambiguous language 

‘‘provide for implementation . . . of 

standards of performance’’ in the 

context of achieving the performance 

rate or emissions goal, to mean that at 

the time the plan is submitted it must 

contain some mechanism to check the 

progress of the plan and correct course. 

The EPA has determined that, for this 

particular rule, the minimum 

mechanism is the set of milestones and 

provisions for corrective measures 

specified in this rule. Indeed, not 

requiring corrective measures in the 

case of deficient plan performance 

would undercut the viability of state 

plan options other than emission 

standard plans with uniform rates 

applied to all affected EGUs within the 

state. 

4. Out-Year Requirements: Maintaining 

or Improving the Level of Emission 

Performance Required by the Emission 

Guidelines 

The agency is determining CO2

emission performance rates and state 

CO2 emission goals for affected EGU 

emission performance based on 

application of the BSER during 

specified time periods. This raises the 

question of whether affected EGU 

emission performance should be 

maintained at the 2030 level—or instead 

should be further improved—once the 

final CO2 emission performance rate or 

state CO2 emission goal is met in 2030. 

This involves questions of performance 

rate and goal-setting as well as questions 

about state planning. The EPA believes 

that Congress either intended the 

emission performance improvements 

required under CAA section 111(d) to be 

maintained or, through silence, 

authorized the EPA to reasonably 

require maintenance. Other CAA section 

111(d) emission guidelines set emission 

limits that do not expire. Therefore, the 

EPA is finalizing that the level of 

emission performance for affected EGUs 

represented by the final CO2 emission 

performance rates or state CO2 emission 

goal must continue to be maintained in 

the years after 2030. 

As noted above, the state plan must 

demonstrate that plan measures are 

projected to achieve the final emission 

performance level by 2030. In addition, 

the state plan must identify 

requirements that continue to apply 

after 2030 and are likely to maintain 

affected EGU emission performance 

meeting the final goal. The state plan 

would be considered to provide for 

maintenance of emission performance 

consistent with the final goal if the plan 

measures used to demonstrate projected 

achievement of the final goal by 2030 

will continue in force and not sunset. 

After implementation, the state is 

required to compare actual plan 

performance against the final goal on a 

2-year average basis starting in 2030, 

and to implement corrective measures 

or a backstop if triggered. 

In the proposal, the EPA noted that 

‘‘CAA section 111(b)(1)(B) calls for the 

EPA, at least every eight years, to review 

and, if appropriate, revise federal 

standards of performance for new 

sources’’ in order to assure regular 

updating of performance standards as 

technical advances provide technologies 

that are cleaner or less costly. The 

proposal ‘‘requests comment on the 

implications of this concept, if any, for 

CAA section 111(d).’’ 79 FR 34830, 

34908/3 (June 18, 2014). 

We acknowledge the obligation to 

review section 111(b) standards as 

stated. The EPA is not finalizing any 

position with respect to any 

implications of this concept for section 

111(d). We are promulgating rules for 

section 111(d) state plans that will 

establish standards of performance for 

existing sources to which a section 

111(b) standard of performance would 

apply if such sources were new sources, 

within the definition in section 

111(a)(2) of ‘‘new source.’’ It is not 

necessary to address at this time 

whether subsequent review and/or 

appropriate revision of the 

corresponding section 111(b) standard 

of performance have any implications 

for review and/or revision of this rule. 

a. Legal basis for maintaining 

emission performance. 

In the proposal, the EPA proposed 

‘‘that the level of emission performance 

for affected EGUs represented by the 

final goal should continue to be 

maintained.’’ The EPA explained that 

‘‘Congress either intended the emission 

performance improvements required 

under CAA section 111(d) to be 

permanent or, through silence, 

authorized the EPA to reasonably 

require permanence. Other CAA section 

111(d) emission guidelines set emission 

limits to be met permanently.’’ 79 FR 

34830, 34908/2 (June 18, 2014). We also 

requested comment on whether ‘‘we 

should establish BSER-based state 

performance goals that extend further 

into the future (e.g. beyond the 

proposed planning period), and if so, 

what those levels of improved 

performance should be.’’ Id. at 34908/3. 

We received adverse comment on 

establishing BSER-based state 

performance goals beyond the proposed 

planning period. Commenters argued 

that we did not have a sufficient basis 

at this time to determine what those 

future goals should be. We agree and 

have decided not to establish such 

goals. We are finalizing, though, that the 

level of emission performance for 

affected EGUs represented by the final 

goal should continue to be maintained, 

for the reasons given in our proposal 

and quoted above. 

The general structure of the CAA 

supports our interpretation. Section 

111(d) plans establish standards of 

performance that reflect the BSER, a 

technology-based standard. Generally 

speaking, in the future technology will 

only improve, and correspondingly the 

CAA does not provide explicit processes 

to relax technology-based standards. In 

contrast, the provisions 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 relaxed 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 ongoing after the CO2 emission 

performance rates or state CO2 emission 

goals are achieved in 2030. This is 

consistent with our past practice for 

section 111(d) rules, which do not 

contain any provision that in the future 

removes or relaxes the promulgated 

guidelines. In light of the persistence of 

CO2 as a pollutant and its long-term 

impacts, it is particularly critical in 

these guidelines to explicitly provide for 

continuing emission reductions. 

G. Additional Considerations for State 

Plans 

1. Consideration of a Facility’s 

‘‘Remaining Useful Life’’ and ‘‘Other 

Factors’’ 

This section discusses the way in 

which the final emission guidelines 

address the CAA section 111(d)(1) 


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855 40 FR 53340 (Nov. 17, 1975). 

856See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12022 

(Mar. 1, 1977); ‘‘Standards of Performance for New 

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

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 facility-specific factors 

and in particular, remaining useful life, 

does not justify a state making further 

adjustments to the performance rates or 

aggregate emission goal that the 

guidelines define for affected EGUs in a 

state and that must be achieved by the 

state plan. Thus, these guidelines do not 

provide for states to make additional 

goal adjustments based on remaining 

useful life and other facility-specific 

factors because they can fully consider 

these factors in designing their plans. 

a. Statutory and regulatory backdrop. 

This section describes the statutory 

and existing regulatory background 

concerning facility-specific 

considerations in implementation of 

section 111(d). 

Section 111(d)(1)(A) requires states to 

submit a plan that ‘‘establishes 

standards of performance’’ for existing 

sources. Under section 111(d)(1)(B), the 

plan must also ‘‘provide for 

implementation and enforcement of 

such standards of performance.’’ 

Finally, the last sentence of section 

111(d)(1) 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 

regulations 855 addressed a number of 

facility-specific factors that might affect 

requirements for an existing source 

under section 111(d). Those regulations 

provide that for designated pollutants, 

standards of performance in state plans 

must be as stringent as the EPA’s 

emission guidelines. Deviation from the 

standard might be appropriate where 

the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control 

resulting from plant age, location, or 

basic process design; 

(2) Physical impossibility of installing 

necessary control equipment; or 

(3) Other factors specific to the facility 

(or class of facilities) that make 

application of a less stringent standard 

or final compliance time significantly 

more reasonable. 

This provision was amended in 1995 

(60 FR 65387, December 19, 1995), and 

is now prefaced with the language 

‘‘Unless otherwise specified in the 

applicable subpart on a case-by-case 

basis for particular designated facilities 

or classes of facilities.’’ 40 CFR 60.24(f). 

b. Our proposal regarding the 

implementing regulations. 

Our proposal stated that the reference 

to ‘‘[u]nreasonable cost of control 

resulting from plant age’’ in 60.24(f) 

‘‘implements’’ the statutory provision 

on remaining useful life. We also stated 

that the implementing regulations 

‘‘provide the EPA’s default structure for 

implementing the remaining useful life 

provision of CAA section 111(d).’’ We 

noted that the prefatory language 

‘‘unless otherwise specified in the 

applicable subpart’’ gives the EPA 

discretion to alter the extent to which 

the implementing rules applied if 

appropriate for a particular source 

category and guidelines. We requested 

comment on our analysis of the existing 

implementing regulations and any 

implications for our regulatory text in 

respect to how these guidelines relate to 

those regulations. 

Commenters stated, among other 

things, that the sentence concerning 

‘‘remaining useful life’’ was added in 

the 1977 CAA Amendments and that 

therefore it could not be said that 

provisions from the 1975 implementing 

regulations ‘‘implement’’ the sentence. 

The EPA does not think as a general 

matter that it is necessarily impossible 

that a pre-statutory amendment rule 

could continue to serve as a reasonable 

implementation of a post-statutory 

amendment provision. However, we 

also think it is appropriate, as we 

suggested in the June 2014 proposal, to 

specify in the applicable subpart for 

these guidelines that the provisions in 

60.24(f) should not apply to the class of 

facilities covered by these guidelines. 

As a result, regardless of whether the 

implementing regulations appropriately 

implement the ‘‘remaining useful life’’ 

provision in general, the relevant 

consideration is that, as we now 

explain, these particular guidelines 

‘‘permit the State in applying a standard 

of performance to any particular source 

under a plan submitted under this 

paragraph to take into consideration, 

among other factors, the remaining 

useful life of the existing source to 

which such standard applies.’’ 

c. How these emission guidelines 

permit states to consider remaining 

useful life and other facility-specific 

factors. 

The EPA notes that, in general, the 

implementing regulation provisions for 

remaining useful life and other facilityspecific factors are relevant for emission 

guidelines in which the EPA specifies a 

presumptive standard of performance 

that must be fully and directly 

implemented by each individual 

existing source within a specified 

source category. Such guidelines are 

similar to a CAA section 111(b) standard 

in their form. For example, the EPA 

emission guidelines for sulfuric acid 

plants, phosphate fertilizer plants, 

primary aluminum plants, Kraft pulp 

plants, and municipal solid waste 

landfills specify emission limits for 

sources.856 In the case of such emission 

guidelines, some individual sources, by 

virtue of their age or other unique 

circumstances, may warrant special 

accommodation. 

In these final guidelines for state 

plans to limit CO2 from affected EGUs, 

however, the agency does not specify 

presumptive performance rates that 

each individual EGU is to achieve in the 

absence of trading. Instead, these 

guidelines provide collective 

performance rates for two classes of 

affected EGUs (steam generating units 

and stationary combustion turbines), 

and give states the alternative of 

developing plans to achieve a state 

emission goal for the collective group of 

all affected EGUs in a state. Providing 

states with the ability to consider 

facility-specific factors such as 

remaining useful life in designing their 

state plans is one of the fundamental 

reasons that the EPA designed the final 

rule in this way. In addition, the 

significant revisions since proposal to 

address achievability concerns (e.g., 

moving the start date from 2020 to 2022, 

and other changes in interim and final 

state goals summarized in the next 

section) will help to ensure that states 

in practice can consider remaining 

useful life and other facility-specific 

factors in setting EGU requirements. Of 

course, EGUs vary considerably in age, 

so remaining useful life is potentially 


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857Trading of course has other benefits beyond 

helping to address remaining useful life concerns. 

For example, trading can lower costs of achieving 

a given level of emission reduction and can provide 

economic incentives for innovation and 

development of cleaner technologies. 

relevant to regulation of some units and 

not others. 

The guidelines capitalize on the 

inherent flexibility offered by the CO2

emission performance rates and by the 

state CO2 emission goals approach, 

allowing states flexibility on the form of 

the EGU standards that they include in 

CAA section 111(d) plans. A state could 

select a form of standards (e.g., 

marketable credits or permits, 

retirement of certain older facilities after 

their useful life, etc.) that avoids or 

diminishes concerns about facilityspecific factors such as remaining useful 

life. If a state adopted the CO2 emission 

performance rates for fossil fuel-fired 

electric utility steam generating units 

and stationary combustion turbines in 

conjunction with rate-based trading, 

though, the state would be taking 

remaining useful life into consideration 

by allowing affected EGUs to comply 

using ERCs. In effect, under a trading 

program with repeating compliance 

periods, a facility with a short 

remaining useful life has a total outlay 

that is proportionately smaller than a 

facility with a long remaining useful 

life, simply because the first facility 

would need to comply for fewer 

compliance periods and would need 

proportionately fewer ERCs than the 

second facility. Buying ERCs would 

avoid excessive up-front capital 

expenditures that might be 

unreasonable for a facility with a short 

remaining useful life, and would reduce 

the potential for stranded assets. 

In addition to providing states with 

flexibility on the form of the standards 

of performance in their plans, the 

guidelines leave to each state the design 

of the specific requirements that fall on 

each affected EGU in applying those 

standards. To the extent that an 

emission standard that a state may wish 

to adopt for affected EGUs raises 

facility-specific issues, the state may 

make adjustments to a particular 

facility’s requirements on facilityspecific 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. 

The EPA believes that this approach 

to permitting states to consider 

remaining useful life is appropriate 

because it reflects, and is compatible 

with, the interconnected nature of the 

electricity system. 

Although this discussion emphasizes 

state flexibility on plan design, it is 

important to note that the main 

intended beneficiaries of state flexibility 

are the affected EGUs themselves. As a 

key case in point, the EPA has 

endeavored to craft the final guidelines 

to support and facilitate state plans that 

include trading systems, including 

interstate trading systems that can help 

EGUs continue to operate with the 

flexibility that they currently enjoy on 

regional grid levels. 

Trading can provide affected EGUs 

that have a limited remaining useful life 

with the flexibility to comply through 

purchasing allowances or ERCs, thereby 

avoiding major capital expenditures that 

would create long-term debt. By buying 

allowances or ERCs, affected EGUs with 

a limited remaining useful life 

contribute to achieving emission 

reductions from the source category 

during the years that they operate. 

During its lifetime, a facility with a 

short remaining useful life will need 

fewer total credits or allowances than an 

otherwise comparable facility with a 

long remaining useful life, but the 

annualized cost to the two facilities is 

the same.857

In part to help states address 

remaining useful life considerations, the 

final guidelines facilitate state plans that 

employ trading in multiple ways: 

• By allowing trading under emission 

standards plans and state measures plans, 

and under rate-based plans and mass-based 

plans; 

• By defining national EGU performance 

rates that make it easier for states to set up 

rate-based trading regimes that allow for 

interstate trading of ERCs; 

• By clearly defining the requirements for 

mass-based and rate-based trading systems to 

ensure their integrity; and 

• By providing information on potential 

allocation approaches for mass-based trading. 

In addition, the EPA is separately 

proposing model trading rules for ratebased and mass-based trading to assist 

states with design of these programs in 

the section 111(d) context. 

d. Why remaining useful life and 

other facility-specific factors do not 

warrant adjustments in the guidelines’ 

performance rates and state goals. 

Under the final guidelines, remaining 

useful life and other facility-specific 

considerations do not provide a basis for 

adjusting the CO2 emission performance 

rates, or the state’s rate-based or massbased 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 

affected EGUs that have a limited 

remaining useful life. State plans may 

use any combination of the emissions 

reduction methods represented by the 

building blocks, and may also choose to 

employ emission reduction methods 

that were not assumed in calculating 

state goals. 

To be more specific, the EPA notes 

that a state is not required to achieve the 

same level of emission reductions with 

respect to any one building block as 

assumed in the EPA’s BSER analysis. A 

state may use any combination of 

measures, including those not 

specifically factored into the BSER by 

the EPA. The EPA has estimated 

reasonable rather than maximum 

possible implementation levels for each 

building block in order to establish EGU 

emission rates and state goals that are 

achievable while allowing states to take 

advantage of the flexibility to pursue 

some building blocks more aggressively, 

and others less aggressively, than is 

reflected in the agency’s computations, 

according to each state’s needs and 

preferences. The guidelines provide 

further flexibility by allowing state 

plans to use emission reduction 

methods not reflected in the BSER. A 

description of multiple emission 

reduction methods is provided in 

sections VIII.I–K. 

e. Response to key comments on 

remaining useful life. 

In response to the proposed 

guidelines, some commenters said that 

the proposed state goals were 


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858Memorandum to Clean Power Plan Docket 

titled ‘‘Stranded Assets Analysis’’ dated July 2015. 

unachievable and therefore too stringent 

to provide states, as a practical matter, 

with the flexibility to consider 

remaining useful life for individual 

units. These commenters said the result 

would be premature retirements and 

stranded assets. 

In the final guidelines, the EPA has 

addressed the comments about lack of 

practical flexibility to consider 

remaining useful life by revising key 

elements of the guidelines in ways that 

will ensure that the CO2 emission 

performance rates and state CO2

emission goals are achievable 

considering cost. At the same time, the 

final guidelines maintain the broad 

flexibility of each state to design its own 

compliance pathway, taking into 

account any facility-level concerns— 

including remaining useful life—in 

designing EGU requirements. 

The changes to the BSER and goalsetting methodologies include: 

• Starting the interim goal period in 2022 

rather than 2020, which allows more lead 

time for states and regulated entities and 

helps to ensure that the interim goal is 

achievable 

• Revising the goal-setting formula and the 

state goals themselves 

• Updating analyses of achievable levels of 

improvement through the building blocks 

that together represent the BSER, while 

keeping them at reasonable, rather than 

maximum, levels (thus creating headroom 

which can, and is intended to, help to 

accommodate the range of ages of different 

facilities) 

• Providing an explicit phase-in schedule for 

meeting the revised interim goals, while 

also allowing a state the option of choosing 

its own emission reduction trajectory 

The final guidelines also contain 

changes to avoid certain inconsistencies 

between the goal-setting methodology 

and accounting of reductions under 

state plans that could have made state 

goals less achievable for some states. 

Together, the changes described above 

help to ensure that the CO2 emission 

performance rates and state CO2

emission goals established in the final 

guidelines are achievable, and leave 

states with the practical ability to issue 

rules that take into account the 

remaining useful life of affected EGU. 

As explained in the Legal 

Memorandum accompanying this rule, 

the EPA believes that Congress intended 

the remaining useful life provision to 

provide a mechanism for states to avoid 

the imposition of unreasonable retrofit 

costs on existing sources with relatively 

short remaining useful lives, a scenario 

that could result in stranded assets. 

However, commenters on the proposed 

rule raised a different stranded assets 

concern not primarily related to retrofit 

costs—a concern that the proposed rule 

could cause changes in economic 

competitiveness of particular EGUs that 

would prompt their retirement before 

the end of their economically useful 

lives. These commenters said the 

proposed state goals were so stringent 

that states would have no choice but to 

adopt requirements that would result in 

retirements of coal-fired capacity that 

had been built relatively recently or had 

recently made pollution control 

investments. In response to these 

comments, the EPA has conducted a 

stranded assets analysis which 

demonstrates that the CO2 emission 

performance rates and state goals in the 

final guidelines provide sufficient 

flexibility to states to address stranded 

asset concerns. The EPA shares the goal 

of minimizing stranded assets. Although 

nothing in section 111(d) explicitly bars 

a guideline that results in some facilities 

becoming uneconomic before the end of 

their useful lives, the EPA nonetheless 

has striven to design the guidelines so 

as to give states flexibility to develop 

plans that include, for example, 

differential treatment of affected EGUs 

or opportunities to rely on emissions 

trading, to allow power companies to 

recover their investments in generation 

units. 

For purposes of the stranded assets 

analysis, the EPA considered a potential 

‘‘stranded asset’’ to be an investment in 

a coal-fired EGU (or in a capitalintensive pollution control installed at 

such an EGU) that retires before it is 

fully depreciated. Book life is the period 

over which long-lived assets are 

depreciated for financial reporting 

purposes. The agency estimated typical 

book life by researching financial 

statements of utility and merchant 

generation companies in filings to the 

Securities and Exchange Commission. 

The agency estimated the book life of 

coal-fired EGUs to be 40 years, and 

assumed a 20-year book life for 

pollution control retrofits. The book life 

of coal-fired EGUs (coal steam and 

IGCC) is twice as long as the debt life 

and the depreciation schedule used for 

federal tax purposes. Although the book 

life for environmental retrofits is often 

15 years, the agency conservatively 

assumed 20 years in this analysis. 

The analysis examined coal 

generation in the three large regional 

interconnections of the U.S. The 

analysis found that in both 2025 and 

2030, for each region, the amount of 

2012 coal generation included in the 

final guidelines’ emission performance 

rate calculation—specifically, the 

generation remaining after the BSER 

calculation—is greater than the amount 

of 2012 generation from coal-fired EGUs 

that are not fully depreciated in those 

years under the book life assumptions 

described above. This shows that the 

final rule allows flexibility for states to 

preserve these units as part of their 

plans. 

To put this analysis in perspective: 

The EPA’s role is to set emission 

guidelines that meet the statutory 

requirements, which includes 

consideration of cost in identifying the 

BSER, as the EPA has done in these 

guidelines. States have a broad degree of 

flexibility to design plans to achieve the 

rates in the emission guidelines in a 

manner that meets their policy 

priorities, including ensuring costeffective compliance. Although not a 

required component of the EPA’s 

consideration of cost, this analysis 

shows that the CO2 emission 

performance rates in the final guidelines 

can be met without the retirement of 

affected EGUs before the end of their 

book life, and without the retirement of 

affected EGUs before the end of the book 

life of capital-intensive pollution 

control retrofits installed on those 

EGUs. Thus, according to this analysis, 

the CO2 emission performance rates and 

state CO2 emission goals need not result 

in stranded assets. The EPA recognizes 

that power plant economics are 

determined by many aspects of markets 

that are outside of the EPA’s control, 

such as wholesale power prices and 

capacity prices, and that the compliance 

path of least cost may involve retiring 

assets that have not fully depreciated. 

Nonetheless, this analysis further 

demonstrates the extent of flexibility 

available to states in designing their 

plans to best serve the policy priorities 

of the state. Details are available in a 

memorandum to the docket.858

Several commenters said that the 

statute does not authorize the EPA to 

require other facilities to achieve greater 

reductions to compensate for a facility 

that warrants relief based on remaining 

useful life. One said that consideration 

of remaining useful life and other 

relevant factors is a one-way ratchet that 

provides relief to sources that cannot 

achieve the BSER, and that the EPA 

turns that approach on its head by 

prohibiting a state from providing such 

relief to a specific facility unless it can 

identify another facility to ‘‘punish’’ by 

requiring additional emissions 

reductions to offset that relief. 

The EPA disagrees with these 

comments, which proceed from an 

incorrect premise. The EPA is not 

determining a BSER-based emission 

level achievable by each individual 

facility without trading, and then 


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859The EPA expects that states that choose to 

adopt the national CO2 emission performance rates 

for all of their EGUs would permit ERC trading, 

rather than requiring each facility to meet the 

applicable rate without trading. In effect, the 

presence of trading means that the EGU 

performance rates can be achieved by each EGU 

involved in trading. 

860Heat rate improvement methods and related 

capital costs are discussed in the GHG Mitigation 

Measures TSD; SO2 scrubber capital costs are from 

the documentation for the EPA’s IPM Base Case 

v5.13, Chapter 5, Table 5–3, available at http://

www.epa.gov/airmarkets/documents/ipm/Chapter_

5.pdf. 

requiring better-than-BSER from some 

facilities to make up for worse-thanBSER performance that a state 

authorizes for other facilities because of 

a short remaining useful life. Rather, as 

previously noted, the guidelines set CO2

emission performance rates and state 

CO2 emission goals that represent the 

average or aggregate emission level 

achievable by affected EGUs based on 

regional average estimates of the impact 

of applying the BSER to collective 

groupings of affected EGUs.859 In 

estimating the amount of improvement 

achievable through each building block 

(e.g., improvement in heat rate or 

amount of generation shift to loweremitting EGUs), the EPA has estimated 

the average level achievable by EGUs in 

a region rather than attempting to 

estimate the level achievable by each 

and every affected EGU in the absence 

of trading. Thus, the fact that an 

individual facility may be unable, for 

example, to achieve the average level of 

heat rate improvement assumed in goalsetting is consistent with the EPA’s 

analysis, and does not undermine the 

EPA’s determination of CO2 emission 

performance rates and state CO2

emission goals. The Legal Memorandum 

discusses additional reasons that the 

agency disagrees with comments that 

the guideline must permit adjustments 

in the guidelines’ CO2 emission 

performance rates and state CO2

emission goals based on remaining 

useful life considerations. 

An additional reason that the EPA 

believes that consideration of remaining 

useful life and other facility-specific 

factors does not warrant adjustments to 

state goals is that the design of the 

guidelines does not mandate that states 

impose requirements that would call for 

substantial capital investments at 

affected EGUs late in their useful life. 

Multiple methods are available for 

reducing emissions from affected EGUs 

that do not involve capital investments 

by the owner/operator of an affected 

EGU. For example, generation shifts 

among affected EGUs, and addition of 

new RE generating capacity do not 

generally involve capital investments by 

the owner/operator at an affected EGU. 

Additional emission reduction methods 

available to states that do not entail 

significant capital costs at affected EGUs 

are discussed elsewhere in this 

preamble. 

Heat rate improvements at affected 

EGUs may require capital investments. 

However, states have flexibility to 

design their plan requirements; they are 

not required to mandate heat rate 

improvements at plants that have 

limited remaining useful life. In fact, a 

state can choose whether or not to 

require heat rate improvements at all. 

The agency also notes that capital 

expenditures for heat rate improvements 

would be much smaller than capital 

expenditures required for example, for 

purchase and installation of scrubbers to 

remove SO2; a fleet-wide average cost 

for heat rate improvements based 

primarily on best practices at coal-fired 

generating units would not likely 

exceed $100/kW, compared with a 

typical SO2 wet scrubber cost of $500/ 

kW (costs vary with unit size).860 Even 

if a state did choose to adopt 

requirements for heat rate 

improvements, the proposed guidelines 

would allow states to regulate affected 

EGUs through flexible regulatory 

approaches that do not require affected 

EGUs to incur large capital costs (e.g., 

averaging and trading programs). Under 

the EPA’s final approach—establishing 

state goals and providing states with 

flexibility in plan design—states have 

flexibility to make exactly the kind of 

judgments necessary to avoid requiring 

capital investments that would result in 

stranded assets. 

Remaining useful life and other 

factors, because of their facility-specific 

nature, are potentially relevant as states 

determine requirements that are directly 

applicable to affected EGUs. If relief is 

due a particular facility, the state has an 

available toolbox of emission reduction 

methods that it can use to develop a 

section 111(d) plan that will achieve the 

CO2 emission performance rates or state 

CO2 emission goals on time. The EPA 

therefore concludes that the remaining 

useful life of affected EGUs, and the 

other facility-specific factors identified 

in the existing implementing 

regulations, should not be regarded as a 

basis for adjusting the CO2 emission 

performance rates or a state CO2

emission goal, and should not relieve a 

state of its obligation to develop and 

submit an approvable plan that achieves 

that goal on time. 

f. Legal considerations regarding 

remaining useful life. Section 111(d)(1) 

requires the EPA in promulgating 

section 111(d) regulations to ‘‘permit the 

State in applying a standard of 

performance to any particular source 

under a plan submitted under this 

paragraph to take into consideration, 

among other factors, the remaining 

useful life of the existing source to 

which such standard applies.’’ Here, we 

discuss the legal basis for determining 

that the emission guidelines are 

consistent with this statutory 

requirement. For details, please see the 

Legal Memorandum. 

Section 111(d)(1) only requires that 

EPA emission guidelines permit states 

to take into account remaining useful 

life (among other factors), but section 

111(d)(1) does not specify how the EPA 

must permit that. In other words, the 

meaning of the provision and the way 

that the EPA is to implement it in 

promulgating guidelines are not 

specified further in the provision. The 

provision is ambiguous and capable of 

implementation in several ways, and 

therefore the EPA has discretion to 

interpret and apply it. Furthermore, 

section 111(d)(1) does not suggest that 

states must be given carte blanche to 

consider remaining useful life in any 

way that can be imagined. As detailed 

above in sections VIII.G.1.c–e, these 

guidelines permit states to take into 

account remaining useful life in a 

number of reasonable ways and thus the 

guidelines satisfy the statutory 

obligation. 

The phrase ‘‘remaining useful life’’ 

also appears in the visibility provisions 

of section 169A. There, in determining 

best available retrofit technology 

(BART), the state (or the EPA) must take 

into consideration (among other factors) 

‘‘the remaining useful life of the 

source.’’ 42 U.S.C. 7491(g)(2); see also 

id. (g)(1) (reasonable progress). In the 

context of the visibility program, we 

have interpreted this provision to mean 

that the remaining useful life should be 

considered when calculating the 

annualized costs of retrofit controls. See 

40 CFR Pt. 51, App. Y, IV.D.4.k.1. This 

annualized cost is then used to 

determine a cost effectiveness, in dollars 

per ton of pollutant removed on an 

annual basis. As a result, a technology 

with a large initial capital cost that 

might have a reasonable costeffectiveness for a facility with a long 

remaining useful life would have a 

much higher and possibly unreasonable 

cost-effectiveness for a facility with a 

short remaining useful life. 

Although section 111(d)(1) is different 

than section 169A(g)(2) and need not be 

interpreted in the same way, we would 

note (as discussed in detail in sections 

VIII.G.1.c–e, section 5.11 of the 

Response to Comments document, and 

the Legal Memorandum) that (for 


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861Casazza, J. and Delea, F., Understanding 

Electric Power Systems: An Overview of the 

Technology, the Marketplace, and Government 

Regulations, IEEE Press, at 160 (2010). 

862 Id. 

863NERC Reliability Standard EOP–001–2.1b— 

Emergency Operations Planning, available at http:// 

www.nerc.net/standardsreports/standards

summary.aspx. 

864Centralized 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. 

example) a trading program under these 

section 111(d) guidelines only requires 

compliance on a periodic basis and does 

not require any initial capital 

expenditures. Thus, over the life of the 

facility, a facility with a short remaining 

useful life will need fewer total credits 

or allowances than an otherwise 

comparable facility with a long 

remaining useful life, but the 

annualized cost to the two facilities is 

the same. In other words, under a 

trading program remaining useful life of 

a source is automatically accounted for 

in the way it is accounted for under the 

visibility program. 

Some commenters stated that the 

EPA’s interpretation of remaining useful 

life is impermissible. These commenters 

claimed that states, if they wish to take 

into account remaining useful life at one 

affected EGU, must relax the stringency 

of the emission standard for that EGU. 

Then, the state would be compelled to 

increase the stringency of emission 

standards at other affected EGUs in 

order to achieve the state performance 

goal. According to these commenters, 

section 111(d) does not allow this 

outcome. 

First, the commenters are mistaken in 

their premise. As discussed in section 

VIII.G.1, section 5.11 of the Response to 

Comments document, the Legal 

Memorandum, and in the example 

immediately above, states can impose 

the exact same emission standards on 

two affected EGUs and still take into 

account remaining useful life through 

the availability of trading. In other 

words, states need not relax an emission 

standard here and strengthen an 

emission standard there in order to take 

into account remaining useful life. 

Thus, these guidelines permit states to 

take into account remaining useful life 

without any of the effects commenters 

are concerned about. 

Second, even if states decide to relax 

emission standards at one EGU, on the 

basis of remaining useful life or any 

other factor, nothing in the last sentence 

of section 111(d)(1) prohibits these 

guidelines from requiring the state plan 

to still meet the CO2 emission 

performance rates or state CO2 emission 

goal. In fact, that sentence is completely 

silent on the issue. Thus, the EPA has 

the discretion to determine what should 

be the concomitant effects if a state 

chooses to consider remaining useful 

life in a particular way. In this case the 

concomitant effect of a state relaxing 

one emission standard may be that the 

state must make up for it elsewhere in 

order to meet the goal, but nothing in 

section 111(d)(1), including the 

statutory requirement to permit 

consideration of remaining useful life, 

prohibits that outcome. 

2. Electric Reliability 

The final rule features overall 

flexibility, a long planning and 

implementation horizon, and a wide 

range of options for states and affected 

EGUs to achieve the CO2 emission 

performance rates or state CO2 emission 

goal. This design reflects, among other 

things, the EPA’s commitment to 

ensuring that compliance with the final 

rule does not interfere with the 

industry’s ability to maintain the 

reliability of the nation’s electricity 

supply. Comments from state, regional 

and federal reliability entities, power 

companies and others, as well as 

consultation with the Department of 

Energy (DOE) and Federal Energy 

Regulatory Commission (FERC), helped 

inform a number of changes made in 

this final rule to address reliability. In 

addition, FERC conducted one national 

and three regional technical conferences 

on the proposed rule in which the EPA 

participated and at which the issue of 

reliability was raised by numerous 

participants. 

As discussed throughout the preamble 

and TSDs, the electricity sector is 

undergoing a period of intense change. 

While the change in the resource mix 

has accelerated in recent years, wind, 

solar, other RE, and EE resources have 

been reliably participating in the 

electric sector for a number of years. 

Many of the potential changes to the 

electric system that the final rule may 

encourage, such as shifts to cleaner 

sources of power and efforts to reduce 

electricity demand, are already well 

underway in the electric industry. To 

the extent that the final rule accelerates 

these changes, there are multiple 

features well embedded in the 

electricity system that ensure that 

electric system reliability will be 

maintained. Electric system reliability is 

continually being considered and 

planned for. For example, in the Energy 

Policy Act of 2005, Congress added a 

section to the Federal Power Act to 

make reliability standards mandatory 

and enforceable by FERC and the North 

American Electric Reliability 

Corporation (NERC), the Electric 

Reliability Organization which FERC 

designated and oversees. Along with its 

standards development work, NERC 

conducts annual reliability assessments 

via a 10-year forecast and winter and 

summer forecasts; audits owners, 

operators, and users for preparedness; 

and educates and trains industry 

personnel. Numerous other entities such 

as FERC, DOE, state PUCs, ISOs/RTOs, 

and other planning authorities also 

consider the reliability of the electric 

system. There are also numerous 

remedies that are routinely employed 

when there is a specific local or regional 

reliability issue. These include 

transmission system upgrades, 

installation of new generating capacity, 

calling on demand response, and other 

demand-side actions. 

Additionally, planning authorities 

and system operators constantly 

consider, plan for, and monitor the 

reliability of the electricity system with 

both a long-term and short-term 

perspective. Over the last century, the 

electric industry’s 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.861

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.862

Mandatory reliability standards apply to 

how the bulk electric system is planned 

and operated. For example, 

transmission operators and balancing 

authorities have to develop, maintain, 

and implement a set of plans to mitigate 

operating emergencies.863

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.864 In February of 2015, 

Midcontinent Independent System 


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865For example, ISO–NE and PJM each filed 

‘‘pay-for-performance’’ proposals to address fuel 

assurance in their regions. FERC recently acted on 

ISO–NE market rule changes providing increased 

market incentives in capacity, energy, and ancillary 

services markets for generators to be available to 

meet their obligations during reserve shortages. ISO 

New England Inc., 147 FERC ¶ 61,172 (2014). 

Additionally, FERC conditionally approved a PJM 

‘‘pay-for-performance’’ proposal that creates a new 

capacity product to provide greater assurance of 

delivery of energy and reserves during emergency 

conditions, establishing credits for superior 

performance and charges for poor performance. PJM 

Interconnection, L.L.C., 151 FERC ¶ 61,208 (2015). 

866For example, Andrew Ott, then Executive Vice 

President-Markets and current President of PJM, an 

RTO with a substantial amount of coal-fired 

capacity and generation, discussed the success of 

PJM’s market design in assuring that PJM met and 

exceeded target reserve margins while MATS was 

being implemented. See Statement of Andrew Ott, 

PJM Executive Vice President-Markets, FERC 

Technical Conference on Centralized Capacity 

Markets in Regional Transmission Organizations 

and Independent System Operators, AD13–7–000, 

at 3, 7 (Sept. 25, 2013), available at http://

www.ferc.gov/EventCalendar/EventDetails.aspx?

ID=6944&CalType=&CalendarID=116&Date=09/25/

2013&View=Listview. At the FERC national Clean 

Power Plan Technical Conference, Michael J. 

Kormos, PJM Executive Vice President-Operations, 

said that PJM’s markets have proven, ‘‘resilient 

enough to respond to different policy initiatives 

. . . Whether it is the Sulfur Dioxide Trading 

Program of the 1990s, the MATS rule or individual 

state RPS initiatives, the markets have been able to 

send the appropriate price signals that produce 

competitive outcomes.’’ See Michael J. Kormos, PJM 

Executive Vice President, Statement at FERC 

Technical Conference on EPA’s Clean Power Plan, 

AD15–4–000, at 3 (Feb. 19, 2015), available at 

http://www.ferc.gov/CalendarFiles/20150213081

650-Kormos,%20PJM.pdf. 

867On May 15, 2015, the five FERC 

Commissioners sent a letter to Acting Assistant 

Administrator Janet McCabe regarding the EPA’s 

Clean Power Plan proposal. See FERC letter, 

available at http://ferc.gov/media/headlines/2015/

ferc-letter-epa.pdf. 

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.865 This is just one of many 

examples where electric system 

regulators and industry participants 

recognize a potential reliability issue 

and are proactively searching for 

solutions. 

The EPA’s approach in this final rule 

is consistent with our commitment to 

ensuring that compliance with the final 

rule does not interfere with the 

industry’s ability to maintain the 

reliability of the nation’s electricity 

supply. Many aspects of the final rule’s 

design are intended to support system 

reliability, especially the long 

compliance period and the basic design 

that allows states and affected EGUs 

flexibility to include a large variety of 

approaches and measures to achieve the 

environmental goals in a way that is 

tailored to each state’s and utility’s 

energy resources and policies. Despite 

the flexibility built into the design of the 

proposal, and the long emission 

reduction trajectory, many commenters 

expressed concerns that the proposed 

rule could jeopardize electric system 

reliability. We note that the EPA has 

received similar comments in EPA 

rulemakings dating as far back as the 

1970s. The EPA has always taken and 

continues to take electric system 

reliability comments very seriously. 

These reoccurring comments with 

regard to reliability notwithstanding, the 

electric industry has done an excellent 

job of maintaining reliability, including 

when it has had to comply with 

environmental rules with much shorter 

compliance periods and much less 

flexibility than this final rule provides. 

Now, more than ever, the electric 

industry has tools available to maintain 

reliability, including mandatory and 

enforceable reliability standards.866

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 approaches that afford 

states and affected EGUs appropriate 

flexibility. EE and other measures that 

were not included in the determination 

of the BSER can strengthen a state’s 

ability to establish a plan to meet the 

CO2 emission performance rates or state 

CO2 emission goals by providing a 

considerable amount of headroom above 

the levels of the rates and goals. EE 

especially, because it reduces load, can 

provide assurance that reliability can 

and will be maintained. Additionally, 

the final rule offers opportunities for 

trading among affected EGUs within and 

between states, and other multi-state 

approaches that will further support 

electric system reliability. 

Second, the final rule provides 

sufficient time to ensure system 

reliability. The final rule retains the 

2030 date for the final period, which 

commenters largely supported as 

reasonable and not a concern for 

reliability, and addresses one of the key 

issues that commenters pointed to as a 

reliability-related concern by both 

moving the start of the interim period 

from 2020 to 2022 and adjusting the 

interim goals to provide a more gradual 

phasing-in of the initial reduction 

requirement and thus a more gradual 

emissions reduction trajectory or glide 

path to the final 2030 goals. These 

changes deliver on the intent of the 

proposal to afford states and affected 

EGUs the latitude to determine their 

own emissions reduction schedules over 

the interim period. Both FERC’s May 15, 

2015 letter 867 and the comment record 

made it clear that providing sufficient 

time for planning and implementation is 

essential to ensuring electric system 

reliability. The EPA has responded by 

providing additional time to allow for 

planning and implementation of the 

final rule requirements, while at the 

same time allowing enough time 

between the beginning of the interim 

period and 2030 to achieve state goals 

or emission performance rates. We note 

that the final rule does not require that 

all states have met their interim goal or 

performance rate by 2022 but rather that 

they meet it on average or cumulatively, 

as appropriate, during the 2022 to 2029 

period. 

As a result of these changes, the states 

themselves will have a meaningful 

opportunity—which, again, many 

commenters suggested the timing and 

stringency of the proposal failed to 

create despite our intent to do so—to 

determine the timing, cadence and 

sequence of actions needed for states 

and sources to meet final rule 

requirements while accommodating the 

ongoing activity needed to ensure 

system reliability. The final rule 

provides more than 6 years before 

reductions are required and an 8-year 

period from 2022 to 2029 to meet 

interim goals. Moreover, while the final 

rule requires each state to submit a plan 

by September 6, 2016, we recognize that 

some states may need more than 1 year 

to complete all of the actions needed for 

their final state plans, including 


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consideration of reliability. Therefore, 

states have the opportunity to receive an 

extension for submitting a final plan. If 

the state needs additional time to 

submit a final plan, then the state may 

submit an initial submittal by 

September 6, 2016, that must address 

three required components sufficiently 

to demonstrate that a state is able to 

undertake steps and processes necessary 

to timely submit a final plan by the 

extended date of September 6, 2018. 

Third, we are including in the final 

rule a requirement that each state 

demonstrate in its final state plan 

submittal that it has considered 

reliability issues in developing its plan. 

This was suggested by a number of 

commenters, and we agree that it is a 

useful element to state plan 

development. 

Fourth, the final rule provides a 

mechanism for a state to seek a revision 

to its plan in order to address changes 

in circumstances that could have 

reliability impacts if not accommodated 

in the plan. The long compliance 

timeframe, with several interim steps, 

naturally provides opportunities for 

states, working with their utilities and 

reliability entities, to assess how 

implementation is proceeding, identify 

unforeseen changes that may warrant 

plan revisions, and work with the EPA 

to make necessary revisions. Similarly, 

the ready availability of emissions 

trading as a compliance tool affords 

EGUs ample flexibility to integrate 

compliance with both routine and 

critical reliability needs. 

Fifth, in response to a variety of 

comments, we are providing a reliability 

safety mechanism that provides a path 

for a state to come to the EPA during an 

immediate, unforeseen, emergency 

situation that threatens reliability to 

notify the EPA that an affected EGU or 

EGUs may need to temporarily comply 

with modified emission standards to 

respond to this kind of reliability 

concern. 

Sixth and finally, we are committed to 

maintaining an ongoing relationship 

with FERC and DOE as this final rule is 

implemented to help ensure continued 

reliable electric generation and 

transmission. 

We provide more details about these 

various elements of the final rule, as 

well as other features of the rule that 

support system reliability, below. 

a. Summary of key comments. 

The EPA received a number of 

comments regarding the proposed rule 

and electric reliability. Many 

commenters provided specific, useful 

ideas regarding changes that could be 

made to the proposal to specifically 

address their reliability concerns. For 

example, many commenters state that 

allowing additional time to comply 

could help in meeting the final rule 

requirements while addressing their 

reliability concerns. Some commenters 

suggest that additional time would 

allow them to evaluate potential 

reliability impacts and system changes 

that need to be made to comply with 

final rule requirements while allowing 

affected EGUs time to meet interim CO2

emissions goals. The EPA also received 

comment that market-based approaches 

have features that could help support 

reliability, and therefore we should 

encourage states to join or form regional 

market-based programs. Commenters 

also stated that the EPA should require 

states to consult with grid operators 

who would analyze the impact of state 

plans on reliability. A number of 

commenters also suggested that the EPA 

should include some sort of reliability 

safety valve in the final rule. We note 

that many participants at the FERC 

technical conferences on the proposed 

rule also discussed a reliability safety 

valve in great detail with many 

suggestions for how such a reliability 

mechanism could be designed. The EPA 

appreciates these and all the comments 

we received regarding the interaction of 

the proposal and electric reliability. We 

have carefully considered all comments, 

consulted further with FERC and 

incorporated many of the suggested 

changes in this final rule. 

b. Final rule flexibility. 

In issuing this final rule, the EPA 

considered public comments on the 

potential interaction between the 

proposal and electric reliability. While 

we have made every effort to develop 

guidelines that would allow states and 

utilities to steer clear of potential 

reliability disruptions, a number of 

commenters argued that the possibility 

of an unanticipated reliability event 

cannot be entirely eliminated. It is 

important to note that there are many 

factors that influence system reliability 

and, given the complexity of the electric 

grid, electric system planners and 

operators likely will not completely 

avoid reliability issues, even in the 

absence of these guidelines. The EPA 

designed the final rule to ensure to the 

greatest extent possible that actions 

taken by states and affected EGUs to 

comply with the final rule do not 

increase potential reliability issues or 

complicate their resolution. In fact, to 

the extent that meeting final rule 

requirements results in the reduction of 

demand, upgrades in transmission 

efficiency and infrastructure, and 

investment in new, more efficient 

technologies, the outcome could be that 

the system is more robust and faces 

fewer risks to electric reliability. 

One specific concern raised by many 

commenters is that the proposed plan 

development schedule may not leave 

sufficient time to conduct reliability 

planning between the development of 

state plans and the proposed start of the 

interim period in 2020. To address these 

concerns and to support a more effective 

reliability planning process, the EPA is 

moving the start of the interim period 

from 2020 to 2022 and adjusting the 

interim goals to provide a gradually 

phased-in initial reduction requirement 

and a more gradual glide path to the 

final 2030 goals. This more gradual 

application of the BSER over the 2022– 

2029 interim period provides the state 

with substantial latitude in selecting the 

emission reduction glide path for 

affected EGUs over that period. As 

noted above, the final rule also provides 

states with up to 3 years to adopt and 

submit their final state plans, and 

afterwards states can, if necessary, 

revise their plans, as discussed in 

section VIII.E.7. This timing gives 

system planners and operators the 

opportunity to do what they have 

already been doing; looking ahead to 

forecast potential contingencies that 

pose reliability risks and identifying 

those actions needed to mitigate those 

risks. The final rule allows states to 

develop a pathway over the interim 

period that reflects their own 

circumstances, such as reflecting 

planned additions and changes in 

generation mix and potentially taking 

advantage of opportunities for trading of 

credits or allowances by affected EGUs 

within and between states. Because 

achievement of the emission rates or 

goals can be demonstrated over several 

years, state plans can accommodate 

situations where, for example, it may 

take time to develop new generation, 

pipelines, or transmission while still 

providing many options for meeting the 

final rule requirements and planning for 

the reliability of the system. 

c. Considering reliability during state 

plan development process. 

Under CAA section 111(d)(1)(B), state 

plans must provide for the 

implementation and enforcement of 

standards of performance for affected 

EGUs. The EPA does not believe a state 

that establishes standards of 

performance for affected EGUs without 

taking reliability concerns into 

consideration satisfactorily provides for 

the implementation of such standards of 

performance as required by CAA section 

111(d)(1)(B), as a serious reliability 

issue would disrupt the state’s provision 


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868While 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. 

869The EPA will still undertake notice and 

comment rulemaking per the requirements of the 

Administrative Procedures Act when acting on such 

state plan revision, but intends to prioritize review 

of plan revisions needed to address reliability 

concerns. 

of implementation of the state plan. 

Therefore, the EPA is requiring that 

each state demonstrate as part of its 

final state plan submission that it has 

considered reliability issues while 

developing its plan in order to ensure 

that standards of performance can be 

implemented and enforced as required 

by the CAA. If system reliability is 

threatened, the ability of affected EGUs 

to meet the requirements of this final 

rule could be compromised if they are 

required to operate beyond the emission 

standards established in state plans in 

order to maintain the reliability of the 

electric grid. The requirement that states 

consider reliability as part of the 

development of state plans is therefore 

designed to ensure that state plans are 

flexible enough to avoid this kind of 

potential conflict between maintaining 

reliability and providing for the 

implementation of emission standards 

for affected EGUs as required by the 

CAA. 

A number of commenters, notably 

ISOs and RTOs, also discussed 

reliability concerns in the context of 

state plans and pointed out that 

planning and anticipation of change are 

among the essential ingredients of 

ensuring the ongoing reliability of the 

electricity system. To that end, they 

recommended that as states are 

developing state plans, their activity 

include the consideration of the 

reliability needs of the region in which 

affected EGUs operate and of the 

potential impact of actions to be taken 

in compliance with state plans. 

Therefore, we are requiring that each 

state demonstrate in its final state plan 

submittal that it has considered 

reliability issues in developing its plan. 

One particularly effective way in which 

states can make this demonstration is by 

consulting with the relevant ISOs/RTOs 

or other planning authorities as they 

develop their plans and documenting 

this consultation process in their state 

plan submissions. If a state chooses to 

consider reliability through consultation 

with the ISO/RTO or other planning 

authority, the EPA recommends that the 

state request that the planning authority 

review the state plan at least once 

during the plan development stage and 

provide its assessment of any reliability 

implications of the plan. Additionally, 

we encourage states that are considering 

reliability through an ISO/RTO or other 

planning authority consultation process 

to have a continuing dialogue with 

those entities during development of 

their final state plan. While following 

the recommendations of the planning 

authority would not be mandatory, the 

state should document its consultation 

process, any response and 

recommendations from the planning 

authority, and the state’s response to 

those recommendations in its final state 

plan submittal to the EPA. This 

consultation is designed to inform how 

the state might adjust its plan for 

meeting the CO2 reduction requirements 

under this guideline; the consultation is 

not a basis for relaxing that requirement. 

While we consider this process to be an 

effective way for a state to demonstrate 

that it considered reliability in 

developing its final state plan, a state 

may provide other comparable support 

for a demonstration that it has 

considered reliability during the state 

plan development process.868 Also as 

discussed elsewhere in this preamble, 

the EPA encourages states to include 

state utility regulators and the state 

energy offices in the development of the 

state plan. These agencies have 

expertise that can help to assure that 

state plans complement the state’s 

power sector. The EPA believes that this 

requirement to demonstrate 

consideration of reliability will provide 

an effective reliability evaluation in the 

state plan development process. It 

should further help states avoid any 

conflicts between state plans and the 

maintenance of reliability during 

implementation of the state plan and 

associated emission standards. Finally, 

we also encourage states as they develop 

their plans to consider, to the extent 

possible, other potential issues that may 

impact affected EGUs. For example, an 

affected EGU may be in an ISO/RTO 

that puts certain deadlines on generators 

that may not line up perfectly with state 

plan deadlines. 

d. State plan modifications. 

If, during the implementation of a 

state plan, a reliability issue cannot be 

addressed within the range of actions or 

mechanisms encompassed in an 

approved state plan, the state can 

submit a plan revision to the EPA to 

amend its plan. In such a circumstance, 

the state plan may need to be adjusted 

to enable affected EGUs to continue to 

meet final rule requirements without 

causing an otherwise unmanageable 

reliability threat. In all cases the plan 

revision must still ensure the affected 

EGUs meet the emission performance 

level set out in the 111(d) final rule. 

Whether or not these circumstances 

occur will depend in part upon how 

each state designs its state plan. States 

that design plans with a high level of 

flexibility, such as market-based plans 

or multi-state plans, are less likely to 

face a potential conflict between state 

plan requirements and the maintenance 

of reliability. States that participate in 

multi-state programs will be better able 

to weather unexpected reliability risks. 

Events not anticipated at the time of 

the final plan submittal—such as the 

retirement of a large low- or zeroemitting unit—may trigger the request 

for state plan revisions. It may also be 

the case that affected EGU-specific 

emission standards in a state plan are 

proving to be too inflexible to allow the 

plan to accommodate market or other 

changes in the power sector. In such 

instances, there should be a lead time 

between the announced retirement of 

the unit and the need to amend the state 

plan. Therefore, the state should be able 

to utilize the revisions process that the 

EPA provides. 

The EPA will review a plan revision 

per the implementing regulation 

requirements of 40 CFR part 60.28. If the 

state’s 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.869

e. Reliability safety valve. 

In this section we describe a 

reliability safety valve, available to 

states with affected EGUs providing 

reliability-critical generation in 

emergency circumstances. Specifically 

and as discussed below the reliability 

safety valve provides i) a 90-day period 

during which the affected EGU will not 

be required to meet the emission 

standard established for it under the 

state plan but rather will meet an 

alternative standard, and ii) a period 

beginning after the initial 90 days 

during which the reliability-critical 

affected EGU may be required to 

continue to operate under an alternative 

standard rather than under the original 

state plan emission standard, as needed 

in light of the emergency circumstances, 

and the state must during this period 

revise its plan to accommodate changes 


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64878 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

870The EPA reserves the right to review such 

notification, and in the event that the EPA finds 

such notification is improper, the EPA may 

disallow the short-term modification and affected 

EGUs must continue to operate under the original 

approved state plan emission standards. 

needed to respond to ongoing reliability 

requirements. Any emissions in excess 

of the applicable state goals or 

performance rates occurring after the 

initial 90-day period must be accounted 

for and offset. 

Many commenters expressed 

concerns that a serious, unforeseen 

event could occur during the final rule 

implementation period that would 

require immediate reliability-critical 

responses by system operators and 

affected EGUs that would result in 

unplanned or unauthorized emissions 

increases. After reviewing the 

comments, we believe that it is highly 

unlikely that there would be a conflict 

between activities undertaken under an 

approved state plan and the 

maintenance of electric reliability, 

except in the case of a state plan that 

puts relatively inflexible requirements 

on specific EGUs. While some have 

pointed out that severe weather or other 

short-term events could potentially 

conflict with state plans, we note that 

most of those events are of short 

duration and would not require major— 

if any—adjustments to emission 

standards for affected EGUs or to state 

plans. For example, during an event like 

the extreme cold experienced in periods 

of the winter of 2013–2014, affected 

EGUs may need to run at a higher level 

for a short period of time to 

accommodate increased demand and/or 

short-term unavailability of other 

generators. However, because 

compliance by affected EGUs will be 

demonstrated over 2–3 years, such a 

short-term event would not cause 

affected EGUs to be out of compliance 

with their applicable emission 

standards. States can also ensure that 

this is true by developing plans that 

allow adequate compliance flexibility to 

accommodate such short-term events. 

We note that we have included in this 

final rule a number of different features 

designed to facilitate emissions trading 

between and among EGUs on an 

interstate basis—and have done so, in 

no small part, in response to comments 

from states and stakeholders seeking to 

put in place or operate under state-level 

and interstate emissions trading 

regimes. Affected EGUs operating in 

those circumstances and operating, in 

addition, subject to state plans that 

incorporate flexible glide paths and 

trading would be able to accommodate 

an unanticipated reliability event. 

We recognize, however, that affected 

EGUs operating in a state with a 

relatively inflexible state plan could 

face unanticipated system emergencies 

that could cause a severe stress on the 

electricity system for a length of time 

such that the requirements in that state’s 

plan may not be achievable by certain 

affected EGUs without posing an 

otherwise unmanageable risk to 

reliability. In particular, there could be 

extremely serious events, outside the 

control of affected EGUs, that would 

require an affected EGU or EGUs 

operating under an inflexible state plan 

to temporarily operate under modified 

emission standards to respond to this 

kind of reliability concern. Examples of 

such an event could include, a 

catastrophic event that damages critical 

or vulnerable equipment necessary for 

reliable grid operation; a major storm 

that floods and causes severe damage to 

a large NGCC plant so that it must shut 

down; or a nuclear unit that must cease 

generating unexpectedly and therefore 

other affected EGUs need to run so as to 

exceed their requirements under the 

approved state plan. This is not an allinclusive list, but the examples 

illustrate several key attributes of the 

kinds of circumstances in which the 

reliability safety valve would apply. 

First, the event creating the reliability 

emergency would be unforeseeable, 

brought about by an extraordinary, 

unanticipated, potentially catastrophic 

event. Second, the relief provided 

would be for EGUs compelled to operate 

for purposes of providing generation 

without which the affected electricity 

grid would face some form of failure. 

Third, the EGU or EGUs in question 

would be subject to the requirements of 

a state plan that imposes emissions 

constraints such that the EGU or EGUs’ 

operation in response to the reliability 

emergency resulted in levels of 

emissions that violated those 

constraints. We do not anticipate that 

EGUs operating under a plan that 

permitted emissions trading would meet 

these criteria. 

The final guidelines provide a 

reliability safety valve for these types of 

situations. If an emergency situation 

arises, the state must submit an initial 

notification to the appropriate EPA 

regional office within 48 hours that it is 

necessary to modify the emission 

standards for a reliability-critical 

affected EGU or EGUs for up to an 

initial 90 days. The notification must 

include a full description, to the extent 

it is known at the time, of the 

emergency situation that is being 

addressed. It must also identify with 

particularity the affected EGU or EGUs 

that are required to run to assure 

reliability. It must also specify the 

modified emission standards at which 

the affected EGU or EGUs will operate. 

The EPA will consider this notification 

to be an approved short–term 

modification to the state plan, allowing 

the EGU to operate at an emission 

standard that is an alternative to the 

emission standard originally specified 

in the relevant state plan, subject to 

confirmation by the further 

documentation described below.870

Within 7 days of submitting the initial 

notification, the state must submit a 

second notification providing 

documentation to the appropriate EPA 

regional office that includes a full 

description of the reliability concern 

and why an unforeseen, emergency 

situation that threatens reliability 

requires the affected EGU or EGUs to 

operate under modified emission 

standards (including discussion of why 

the flexibilities provided under the 

state’s plan are insufficient to address 

the concern). The state must also 

describe in its documentation how it is 

coordinating or will coordinate with 

relevant reliability coordinators and 

planning authorities to alleviate the 

problem in an expedited manner, and 

indicate the maximum time that the 

state anticipates the affected EGU or 

EGUs will need to operate in a manner 

inconsistent with its or their obligations 

under the state’s approved plan, and the 

modified emission standards or levels at 

which the affected EGU or EGUs will be 

operating at during this period if it has 

changed from the initial notification. 

The documentation must also include a 

written concurrence from the relevant 

reliability coordinator and/or planning 

authority confirming the existence of 

the imminent reliability threat and 

supporting the temporary modification 

request or an explanation of why this 

kind of concurrence cannot be provided. 

Additionally, if the relevant planning 

authority has conducted a system-wide 

or other analysis of the reliability 

concern, the state must include that 

information in its request. If the state 

fails to submit this documentation on a 

timely basis, the EPA will notify the 

state, which must then notify the 

affected EGU(s) that they must operate 

or resume operations under the original 

approved state plan emission standards. 

It is important to note that the affected 

EGUs must continue to monitor and 

report their emissions and generation 

pursuant to requirements in this final 

rule and under the state plan during any 

short-term modification. For the 

duration of the up to 90-day short-term 

modification, the emissions of the 

affected EGU or EGUs that exceed their 

obligations under the approved state 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64879 

871M.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. 

872North American Electric Reliability 

Corporation, Potential Reliability Impacts of EPA’s 

Continued 

plan will not be counted against the 

state’s overall goal or emission 

performance rate for affected EGUs. 

Such a modification will not alter or 

abrogate any other obligations under the 

approved state plan. 

During this short-term modification 

period, the EPA expects that the source, 

the state and the relevant reliability 

coordinator and/or planning authority 

will assess whether the reliability issue 

can be addressed in a way that would 

allow the EGU or EGUs to resume 

operating under the original approved 

state plan within the 90-day period or 

whether revisions to the state plan need 

to be made to address the unexpected 

circumstances for the longer term (the 

unexpected unavailability of a nuclear 

unit, for example). 

The EPA recognizes that an 

emergency may persist past 90 days. At 

least 7 days before the end of the initial 

90-day reliability safety valve period, 

the state must notify the appropriate 

EPA regional office whether the 

reliability concern has been addressed 

and that the EGU or EGUs can resume 

meeting the original emission standards 

established in the state plan prior to the 

short-term modification. 

If there still is a serious, ongoing 

reliability issue at the end of the shortterm modification period that 

necessitates the EGU or EGUs to emit 

beyond the amount allowed under the 

state plan, the state must provide to the 

EPA a notification that it will be 

submitting a state plan revision and 

submit the plan revision as 

expeditiously as possible, specifying in 

the notice the date by which the 

revision will be submitted. The state 

must document the ongoing emergency 

with a second written concurrence from 

the relevant reliability coordinator and/ 

or planning authority confirming the 

continuing urgent need for the EGU or 

EGUs to operate beyond the 

requirements of the state plan and that 

there is no other reasonable way of 

addressing the ongoing reliability 

emergency but for the EGU or EGUs to 

operate under an alternative emission 

standard than originally approved under 

the state plan. In this event, the EPA 

will work with the state on a case-bycase basis to identify an emission 

standard for the affected EGU or EGUs 

for the period before a new state plan 

revision is approved. After the initial 

90-day period, any excess emissions 

beyond what is authorized in the 

original approved state plan will count 

against the state’s overall goal or 

emission performance rate for affected 

EGUs. 

The EPA intends for this reliability 

safety valve to be used only in 

exceptional situations. In addition, this 

reliability safety valve applies only to 

this final rule and has no effect on CAA 

requirements to which the state or the 

affected EGUs are otherwise subject. As 

discussed earlier, we are providing 

states with the flexibility to design 

programs that allow affected EGUs to 

meet compliance obligations while 

responding to reliability needs, even in 

emergency situations. This flexibility 

means that a conflict between the 

requirements of the state plan and 

maintenance of reliability should be 

extremely rare. We recognize, however, 

that a state with an inflexible plan could 

be faced with more than one emergency 

and in this case the reliability safety 

valve may be used more than once. If 

the state finds that a second reliability 

emergency arises that conflicts with the 

state plan, the state must submit a 

revision to its state plan so that the state 

plan is flexible enough to assure that 

such conflicts do not recur and that the 

state is providing for the 

implementation of the standards of 

performance for affected EGUs as 

required by the CAA. 

f. Coordination among federal 

partners. 

The EPA, DOE, and FERC have agreed 

to coordinate efforts to help ensure 

continued reliable electricity generation 

and transmission during the 

implementation of the final rule. The 

three agencies have developed a 

coordination strategy that reflects their 

joint understanding of how they will 

work together to monitor final rule 

implementation, share information, and 

resolve any difficulties that may be 

encountered. This strategy is based on 

the successful working relationship that 

the three agencies established in their 

joint effort to work together to monitor 

reliability during MATS 

implementation. 

g. Analyses of the reliability impacts 

of the proposal. 

The EPA appreciates that a large 

number of entities from many different 

industry perspectives have published 

reports and analysis with respect to 

electric reliability and the 111(d) 

proposed rule. We take concerns about 

reliability very seriously, and we 

appreciate the attention given to this 

issue in the comments and shared with 

us in public forums. It is important to 

note that these studies were conducted 

prior to promulgation of this final rule, 

and thus were only able to consider 

electric reliability with respect to the 

proposal. The EPA has made changes 

and improvements to the proposal in 

response to comments and new 

information, and some of the changes 

are relevant to the final rule’s potential 

effect on electric reliability. One notable 

change pertains to the start of the 

interim period, which is now 2022 

rather than 2020. Another important 

change to the final rule is a more 

gradual phase-in of the BSER for 

affected EGUs over the interim period 

(from 2022 through 2029). The final rule 

also provides considerable flexibility 

and multiple pathways to states, 

including allowing their EGUs to use 

multi-state trading and other 

approaches, which would allow 

essential units to continue to meet their 

compliance obligation while generating 

even at unplanned but reliability-critical 

levels. In addition, we have included in 

the final rule a reliability safety valve 

provision that can be utilized in certain 

emergency situations. These changes, in 

addition to already existing industry 

mechanisms and planning 

requirements, will help to ensure that 

industry will be able to maintain 

electric reliability. The EPA is confident 

that the final rule will cut harmful 

electric power plant pollution while 

maintaining a reliable electric grid 

because the final rule provides industry 

with the time and flexibility needed to 

continue its current and ongoing 

planning and investing to modernize 

and upgrade the electric power system. 

In June of 2015, M.J. Bradley & 

Associates issued a report that 

enumerated a set of useful guiding 

principles for studying and evaluating 

the reliability impacts of the final 

rule.871 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 

maximize reliability; and (6) a study 

should provide realistic and reliabilityfocused 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 2015.872 The EPA 


tkelley on DSK3SPTVN1PROD with BOOK 2
64880 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

Proposed Clean Power Plan (Nov. 5, 2014), 

available at http://www.nerc.com/news/Pages/

Reliability-Review-of-Proposed-Clean-Power-PlanIdentifies-Areas-for-Further-Study,-MakesRecommendations-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-UsesScenario-Analysis-to-Identify-Potential-ReliabilityRisks-from-Proposed-Clean-Power-Plan.aspx. 

873EIA, Annual Energy Outlook 2015, with 

Projections to 2040, April 2015, available at http:// 

www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf. 

874Brattle 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/file-2486162659-pdf/PDF/EPAsClean-Power-Plan-ReliabilityBrattle.pdf?t=1434398407867. 

875See 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%20Material/

EPA%20Regulations/AnalysisofEPAProposal

ReduceCO2Emissions.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%20Results%20Final%20Version.pdf; 

ERCOT, ERCOT Analysis of the Clean Power Plan 

(Nov. 17, 2014), available athttp://www.ercot.com/ 

content/news/presentations/2014/ERCOTAnalysisImpactsCleanPowerPlan.pdf; and 

876MISO, 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%20Material/

EPA%20Regulations/AnalysisofEPAProposal

ReduceCO2Emissions.pdf. 877SPP, 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%20

Results%20Final%20Version.pdf. 878Analysis Group, Electric System Reliability 

and EPA’s Clean Power Plan: The Case of MISO 

(June 8, 2015), available at http://www.analysis

group.com/uploadedfiles/content/insights/

publishing/analysis_group_clean_power_plan_

miso_reliability.pdf. 879Analysis 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/publishing/analysis_group_clean_power_

plan_miso_reliability.pdf. 

880ERCOT, ERCOT Analysis of the Clean Power 

Plan (Nov. 17, 2014), available at http://www.ercot.

com/content/news/presentations/2014/ERCOT

Analysis-ImpactsCleanPowerPlan.pdf. 

881ERCOT, ERCOT Analysis of the Clean Power 

Plan, at 9 (Nov. 17, 2014), available at http://www.

ercot.com/content/news/presentations/2014/

ERCOTAnalysis-ImpactsCleanPowerPlan.pdf. 

882Brattle 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/integratingrenewable-energy-into-the-electricity-grid. 

883PJM, PJM Interconnection Economic Analysis 

of the EPA Clean Power Plan Proposal (Mar. 2, 

2015), report listed at http://www.pjm.com/

documents/reports.aspx. 

884WECC, EPA Clean Power Plan: Phase I— 

Preliminary Technical Report (Sept. 19, 2014), 

available at https://www.wecc.biz/_layouts/15/

WopiFrame.aspx?sourcedoc=/Reliability/140912_

EPA-111(d)_PhaseI_Tech-Final.pdf&

action=default&DefaultItemOpen=1. 

appreciates NERC’s attention to, and 

interest in, the proposed rule. However, 

we note that like some other studies, 

NERC assumes considerably less 

flexibility than actually is provided to 

states and EGUs in this final rule. The 

final rule provides states with 

considerable time and latitude in 

designing plans that are tailored to the 

system in which their EGUs operate, 

which should be reflected in any 

reliability analysis. Also, the NERC 

study does not fully reflect the current 

electric grid. For example, the amount 

of RE generation that NERC assumes for 

2020 is similar to levels of generation 

that we see today whereas projections 

for 2020 are considerably higher.873

Further, NERC conflates retirements that 

may happen as a result of the rule with 

those that are already planned. The 

Brattle Group has also reviewed NERC’s 

November 2014 initial analysis of the 

proposed rule, noting that it is 

important to distinguish between 

concerns about the building blocks and 

reliability concerns about compliance 

with state plans.874 The Brattle Group 

concluded that there are real world 

solutions to NERC’s concerns. These 

include making use of the many flexible 

options available to states under the rule 

to mitigate reliability risks. 

Multiple ISOs/RTOs also provided 

analyses of the proposed rule, including 

MISO, PJM, ERCOT, and SPP.875 For 

example, MISO conducted an analysis 

of coal units at risk for retirement, 

finding that 14 GW of coal may be at 

risk.876 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.877 While we 

appreciate MISO’s and SPP’s concerns 

regarding retirements and the potential 

that reserves will fall below reserve 

requirement levels, it is important to 

consider the many ways in which states 

can develop plans that account for their 

potential reliability concerns. The final 

rule continues to give states significant 

flexibility in how they comply with 

requirements, including both BSER 

measures and measures that were not 

included in the determination of the 

BSER as a means to comply. For 

example, demand-side EE measures can 

greatly assist states and affected EGUs in 

meeting the standards and/or state plan. 

Many studies assume that state plans 

will simply apply the BSER and do not 

recognize the large number of 

compliance approaches and 

opportunities that states and affected 

EGUs have available to them. The 

Analysis Group recently analyzed 

reliability considerations in MISO as the 

region considers how to comply with 

the final rule.878 The Analysis Group 

found that despite the large amount of 

coal-fired generating capacity that will 

likely be retired in MISO in the coming 

years, the entities responsible for 

electric system reliability in MISO are 

prepared to collaboratively address any 

reliability issues that arise and that 

there is a ‘‘strong tool kit for managing 

‘Essential Reliability Services’ needed to 

assure high-quality electric service.’’ 879

ERCOT also performed an analysis, 

modeling numerous scenarios.880

ERCOT stated that its modeling 

identified two potential reliability 

problems—impacts of units retiring and 

increased levels of renewable generation 

on the ERCOT grid.881 As noted above, 

the final rule gives additional time for 

compliance, providing needed time to 

obtain new or replacement generation 

necessary as some existing generators 

retire. Moreover, affected EGUs needed 

for reliability should be able to employ 

the flexibilities afforded to them as they 

seek lower and zero-emitting generation. 

Finally, we note that ERCOT has a 

history of notable success in integrating 

RE into its electric grid, giving ERCOT 

significant expertise regarding 

challenges that may arise with the 

addition of new RE in order to comply 

with the final rule. In fact, a recent 

Brattle Group report used ERCOT as a 

case study for how to effectively 

integrate a large number of RE into the 

electric grid.882

PJM conducted its own analysis at the 

request of the Organization of PJM 

States (OPSI).883 This analysis is 

consistent with many of the M.J. 

Bradley guiding principles. PJM 

designed various scenarios to capture 

the impact of the proposed rule under 

a series of assumptions. Because the 

EPA had not yet issued the final rule, 

PJM cautioned against using the report 

as a reliability analysis or predictor of 

the future. PJM stated that, since 2007, 

PJM’s capacity markets have helped to 

attract 35,000 MWs of additional 

generation. Even though 26,000 MWs 

will retire between 2009 and 2016, the 

PJM capacity market has procured 

sufficient resources to maintain 

reliability. 

WECC also produced a study which is 

part of a longer-term, phased effort.884

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 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64881 

885WECC, 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=/Reliability/140912_

EPA-111(d)_PhaseI_Tech-Final.pdf&action=default

&DefaultItemOpen=1. 

886WECC, 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=/Reliability/

140912_EPA-111(d)_PhaseI_Tech-Final.pdf

&action=default&DefaultItemOpen=1. 

887Analysis Group, Electric System Reliability 

and EPA’s Clean Power Plan Tools and Practices 

(Feb. 2015), available at http:// 

www.analysisgroup.com/uploadedfiles/content/

insights/publishing/electric_system_reliability_and_

epas_clean_power_plan_tools_and_practices.pdf. 

888Analysis 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/publishing/electric_system_reliability_and_

epas_clean_power_plan_tools_and_practices.pdf. 

889http://www.eda.gov/power/. 

890https://www.whitehouse.gov/the-press-office/

2015/03/27/fact-sheet-partnerships-opportunityand-workforce-and-economic-revitaliz. 

independent analysis of this issue.’’ 885

WECC concluded that the effects of the 

proposal on resource adequacy may be 

minimal but that resource adequacy 

cannot be fully assessed without 

realistic and/or proposed compliance 

scenarios.886

Analysis Group analyzed the 

proposed rule, finding that it provides 

states and affected EGUs with a wide 

range of options and operational 

discretion that can prevent reliability 

issues while also reducing carbon 

pollution and costs.887 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.888 It stated 

that these assumptions are not 

consistent with past actions. 

We appreciate the time that multiple 

entities took to analyze and consider the 

potential impacts of the proposed rule. 

As we issue the final rule and states 

draft plans to implement the rule, we 

look forward to further analysis by these 

and other groups. Such analysis can 

provide states with needed resources to 

help them design state plans that will 

augment the efforts of the industry to 

maintain electric reliability. 

3. Consideration of Effects on 

Employment and Economic 

Development 

States in designing their state plans 

should consider the effects of their 

plans on employment and overall 

economic development to assure that 

the opportunities for economic growth 

and jobs that the plans offer are 

manifest. To the extent possible, states 

should try to assure that any 

communities that can be expected to 

experience job losses can also take 

advantage of the opportunities for job 

growth or otherwise transition to 

healthy, sustainable economic growth. 

The EPA’s illustrative analysis indicates 

that there may be some additional job 

losses in sectors related to coal 

extraction and generation that are 

attributable to implementation of this 

rule. At the same time, the EPA’s 

illustrative analysis indicates that there 

may be new jobs in the utility power 

sector associated with both improving 

the efficiency of fossil fuel-fired power 

plants, construction and operation of 

new natural gas-fired and RE 

production, and actions to increase 

demand-side EE. Consideration of these 

effects in the context of the particulars 

of the state plan can help states craft 

plans that, to the extent possible, meet 

multiple environmental, economic, and 

workforce development goals. 

The Partnerships for Opportunity and 

Workforce and Economic Revitalization 

(POWER) Initiative is a new interagency 

effort led by the Economic Development 

Administration in the Department of 

Commerce. POWER was launched to 

respond to current trends in the power 

sector: ‘‘The United States is undergoing 

a rapid energy transformation, 

particularly in the power sector. This 

transformation is producing cleaner air 

and healthier communities, and 

spurring new jobs and industries. At the 

same time, it is impacting workers and 

communities who have relied on the 

coal industry as a source of good jobs 

and economic prosperity, particularly in 

Appalachia, where competition with 

other coal basins provides additional 

pressure.’’ 889 The POWER Initiative 

aligns, leverages, and targets economic 

and workforce development assistance 

to communities and workers affected by 

changes in the coal industry and the 

utility power sector. The POWER 

Initiative is competitively awarding 

planning assistance and implementation 

grants with funding from the 

Department of Commerce, Department 

of Labor, Small Business 

Administration, and the Appalachian 

Regional Commission to partnerships 

anchored in impacted communities. 

These grants will help communities 

organize themselves, develop 

comprehensive strategic plans that chart 

their economic future, and execute 

coordinated economic and workforce 

development activities based on their 

strategic plans.890

In addition to POWER, however, the 

EPA encourages states to use economic 

and labor market analysis to identify 

where they can deploy strategies to: (1) 

Provide a range of employment and 

training assistance to workers, and 

economic development assistance to 

communities affected by the rapid 

changes underway in the power sector 

and closely related industries, to 

diversify their economies, attract new 

sources of investment, and create new 

jobs; and (2) mobilize existing education 

and training resources, including those 

of community and technical colleges 

and registered apprenticeship programs, 

to ensure that both incumbent and new 

workers are trained for the skills 

necessary to meet employer demand for 

new workers in the utility, construction 

and related sectors, that such training 

includes career pathways for members 

of low-income communities and other 

vulnerable communities to attain 

employment in these sectors, and that 

such training results in validated skill 

certifications for workers. 

4. Workforce Considerations 

Some stakeholders commented that, 

to ensure that emission reductions are 

realized, it is important that 

construction, operations and other 

skilled work undertaken pursuant to 

state plans is performed to 

specifications, and is effective, safe, and 

timely. A good way to ensure a highly 

proficient workforce is to require that 

workers have been certified by: (1) An 

apprenticeship program that is 

registered with the U.S. DOL, Office of 

Apprenticeship or a state 

apprenticeship program approved by 

the DOL; (2) a skill certification aligned 

with the U.S. DOE Better Building 

Workforce Guidelines and validated by 

a third party accrediting body 

recognized by DOE; or (3) other skill 

certification validated by a third party 

accrediting body. 

5. Tenth Amendment Legal 

Considerations 

Some commenters have raised 

concerns that the emission guidelines 

and requirements for 111(d) state plans 

violate principles of federalism 

embodied in the U.S. Constitution, 

particularly the Tenth Amendment. 

These commenters claim that states will 

be unconstitutionally ‘‘coerced’’ or 

‘‘commandeered’’ into taking certain 

actions in order to avoid the prospect of 

either a federal 111(d) plan applying to 

sources in the state, or of losing federal 

funds. 

We disagree on both fronts. First, the 

prospect of a federal plan applying to 

sources in a state does not ‘‘coerce’’ or 


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64882 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

891Among 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. 

892See, e.g., Hodel v. Va. Surface Mining & 

Reclamation Ass’n, Inc., 452 U.S. 264, 283–93 

(1981); Texas v. EPA, 726 F.3d 180, 196–97 (D.C. 

Cir. 2013) (noting that ‘‘Supreme Court precedent 

repeatedly affirm[s] the constitutionality of federal 

statutes that allow States to administer federal 

programs but provide for direct federal 

administration if a State chooses not to administer 

it’’). 

893Other 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). 

894 40 CFR 52.30 (defining ‘‘plan or plan item’’). 

‘‘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.891

This approach is consistent with 

ordinary cooperative federalism regimes 

that federal courts have routinely 

upheld against Tenth Amendment 

challenges.892

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.893 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 110.894

The EPA never intended to even 

imply that we would contemplate using 

this authority to encourage state 

participation in this rule under section 

111. To the contrary, we believe that 

imposition of a federal plan rather than 

sanctions is the appropriate path in the 

context of this program. Accordingly, 

regardless of whether the EPA could 

theoretically apply discretionary 

sanctions against states in the section 

111(d) context, the final rule forbids the 

agency from exercising any such 

authority. We have included in this rule 

a provision that prohibits the agency 

from imposing sanctions in the event 

that a state fails to submit or implement 

a satisfactory plan under this rule. As 

states consider whether to take 

advantage of the opportunity to develop 

state plans, they can be assured that the 

EPA will not withdraw federal funding 

should they decline to participate. 

6. Title VI 

States that are recipients of EPA 

financial assistance must comply with 

all federal nondiscrimination statutes 

that together prohibit discrimination on 

the bases of race, color, national origin 

(including limited-English proficiency), 

disability, sex and age. These laws 

include: Title VI of the Civil Rights Act 

of 1964; Section 504 of the 

Rehabilitation Act of 1973; Section 13 of 

the Federal Water Pollution Control Act 

Amendments of 1972; Title IX of the 

Education Act Amendments of 1972; 

and the Age Discrimination Act of 1975. 

Compliance with these 

nondiscrimination statutes is a 

recipient’s separate and distinct 

obligation from compliance with 

environmental regulations. In other 

words, all recipients are required to 

ensure that all aspects of their state 

plans do not violate any of the federal 

nondiscrimination statutes, including 

Title VI. 

The EPA’s Office of Civil Rights 

(OCR) is responsible for carrying out 

compliance with these federal 

nondiscrimination statutes and does so 

through a variety of means including: 

Complaint investigation; agencyinitiated compliance reviews; pre-grant 

award assurances and audits; and 

technical assistance and outreach 

activities. Anyone who believes that any 

of the federal nondiscrimination laws 

enforced by OCR have been violated by 

a recipient of EPA financial assistance 

may file an administrative complaint 

with the EPA’s OCR. 

H. Resources for States To Consider in 

Developing Plans 

As part of the stakeholder outreach 

and comment processes, the EPA asked 

states what the agency could do to 

facilitate state plan development and 

implementation. In addition, after the 

comment period closed, the EPA 

continued to consult with state 

organizations including the Association 

of Air Pollution Control Agencies 

(AAPCA), Environmental Council of the 

States (ECOS), National Association of 

Clean Air Agencies (NACAA), National 

Association of Regulatory Utility 

Commissioners (NARUC), National 

Association of State Energy Officials 

(NASEO) and the National Governors 

Association (NGA). 

Some states indicated that they 

wanted the EPA to create resources to 

assist with state plan development, 

especially resources related to 

accounting for RE and demand-side EE 

in 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 demand-side EE programs using 

established EM&V protocols. 

The EPA also heard that states would 

like guidance on plan development to 

be released at the same time as this final 

rule. This guidance should include 

allowable programs and policies for 

compliance, examples of compliance 

pathways, clear information on multistate 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 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64883 

895Monitoring and reporting requirements for 

affected EGU CO2 emissions and useful energy 

output are addressed in section VIII.F. 

896 ‘‘Integrated RE’’ refers to RE that is directly 

incorporated into the mechanical systems and 

operation of the EGU. An example is a solar thermal 

energy system used to preheat boiler feedwater. 

Such approaches reduce the amount of fossil fuel 

heat input per unit of useful energy output. 

897The 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 retrofitte EGU CHP 

market consists of converted simple cycle turbines, 

older steam plants in urban areas, and combined 

cycle units near beneficial thermal loads. 

898Addition 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. 

899Standards of Performance for Greenhouse Gas 

Emissions from New, Modified, and Reconstructed 

Stationary Sources: Electric Utility Generating 

Units. 900The final CAA section 111(b) rule finalizes 

amendments to subpart PP reporting requirements, 

specifically requiring that the following pieces of 

information be reported: (1) The electronic GHG 

Reporting Tool identification (e-GGRT ID) of the 

EGU facility from which CO2 was captured, and (2) 

the e-GGRT ID(s) for, and mass of CO2 transferred 

to, each GS site reporting under subpart RR. As 

noted, the final 111(b) rule also requires that any 

affected EGU unit that captures CO2 to meet the 

applicable emission limit must transfer the 

captured CO2 to a facility that reports under 40 CFR 

part 98 subpart RR. 

901Under final requirements in the CAA 111(b) 

NSPS, any well receiving CO2 captured from an 

affected EGU, be it a Class VI or Class II well, must 

report under subpart RR. A UIC Class II well’s 

regulatory status does not change because it 

receives such CO2, nor does it change by virtue of 

reporting under subpart RR. 

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 Web site does not 

necessarily imply the approvability of 

an approach or method for use in a state 

plan. States will need to demonstrate 

that any measure included in a state 

plan meets all relevant criteria and 

adequately addresses elements of the 

plan components discussed in section 

VIII.D of this preamble. 

I. Considerations for CO2 Emission 

Reduction Measures That Occur at 

Affected EGUs 

This section describes a range of 

emission reduction actions that may be 

taken at affected EGUs that reduce CO2

emissions from an affected EGU and/or 

improve its CO2 emission rate, and the 

accounting treatment for these actions 

in a state plan. Some of these actions do 

not necessitate additional accounting, 

monitoring or reporting requirements. 

Such actions are discussed in section 

VIII.I.1 below, and include heat rate 

improvements, fuel switching from one 

fossil fuel to another, integration of RE 

into EGU operations, and combined heat 

and power (CHP) expansion or retrofit. 

Other actions, however, do necessitate 

additional accounting, monitoring, or 

reporting requirements. These include 

use of CCS, CCU and biomass, as 

discussed in section VIII.I.2 below. 

The discussion in this section applies 

for both rate-based and mass-based 

plans. Additional accounting 

considerations for mass-based plans are 

discussed in section VIII.J. Additional 

accounting considerations for rate-based 

plans, including how actions that 

substitute for generation from affected 

EGUs or avoid the need for generation 

from affected EGUs may be used in a 

state plan to adjust the CO2 emission 

rate of an affected EGU, are discussed in 

section VIII.K. 

1. Actions Without Additional 

Accounting and Reporting 

Requirements 

Many actions will reduce the reported 

CO2 emissions or CO2 emission rate of 

an affected EGU, without the need for 

additional accounting or monitoring and 

reporting requirements beyond the 

required CEMS tracking of actual stack 

CO2 emissions and tracking of actual 

energy output.895 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; 896 and 

• CHP, including retrofit of an affected 

EGU to a CHP configuration, or revising the 

useful energy outputs (electrical and thermal) 

at an affected EGU already operating in a 

CHP configuration.897

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 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.898 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.899 Specifically, the final CAA 

section 111(b) rule for new sources 

requires that, if a new affected EGU uses 

CCS to meet the applicable CO2

emission limit, the EGU must report in 

accordance with 40 CFR part 98 subpart 

PP (Suppliers of Carbon Dioxide), and 

the captured CO2 must be injected at a 

facility or facilities that report in 

accordance with 40 CFR part 98 subpart 

RR (Geologic Sequestration of Carbon 

Dioxide).900,901 See 40 CFR 60.5555(f). 

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, nonNGCC generating options. In the June 

2014 proposal, the EPA noted that CCS 

technology at existing EGUs would 

entail additional considerations beyond 

those at issue for newly constructed 

EGUs. Specifically, the cost of 

integrating a retrofit CCS system into an 

existing facility may be expected to be 

substantial, and some existing EGUs 

may have space limitations and thus 

may not be able to accommodate the 

expansion needed to install the 

equipment to implement CCS. Further, 

the EPA noted that aggregated costs of 

applying CCS as a component of the 

BSER for the large number of existing 

fossil fuel-fired steam EGUs would be 

substantial and would be expected to 

affect the cost and potentially the 

supply of electricity on a national basis. 

Because there are lower-cost systems of 

emission reduction available to reduce 

emissions from existing plants, the EPA 


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64884 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

902http://skyonic.com/technologies/skymine. 

903http://www.calera.com/beneficial-reuse-ofco2/process.html. 

904http://www.newskyenergy.com/index.php/

products/carboncycle. 

905www.epa.gov/climatechange/downloads/

Framework-for-Assessing-Biogenic-CO2- 

Emissions.pdf. 

906www.epa.gov/climatechange/ghgemissions/

biogenic-emissions.html. 

did not propose nor finalize CCS as a 

component of the BSER for existing 

EGUs. 

However, the EPA noted that CCS 

may be a viable CO2 mitigation 

technology at some existing sources and 

that it would be available to states and 

to sources as a compliance option. 

Numerous commenters agreed with the 

EPA’s proposed determination that CCS 

technology is not part of the BSER 

building blocks for existing EGUs. Other 

commenters opposed inclusion of CCS 

requirements in state plans and 

provided specific reasons why CCS 

would not be applicable in certain 

states. Many commenters felt that CCS 

technology is not adequately 

demonstrated and is not economically 

practical at this time. Other commenters 

argued that CCS is an available 

technology and that it can be 

implemented at more EGUs than 

predicted by EPA modeling. 

Some commenters noted that there are 

opportunities to reduce the cost of CCS 

implementation by selling the captured 

CO2 for use in Enhanced Oil Recovery 

(EOR) operations. One commenter 

expressed concern that federal 

requirements under the Greenhouse Gas 

Reporting Program—specifically the 

requirement (mentioned above) to report 

under 40 CFR part 98 subpart RR— 

would foreclose, rather than encourage, 

the use of captured CO2 for EOR. The 

EPA received similar public comments 

on the CAA 111(b) proposal for new 

EGUs. The EPA disagrees with the 

commenters’ assertions and addressed 

those in the preamble for the final 

standards of performance and in the 

Response-to-Comments (RTC) document 

for the CAA 111(b) NSPS rulemaking. 

The EPA noted that the cost of 

compliance with subpart RR is not 

significant enough to offset the potential 

revenue for the EOR operator from the 

sale of produced oil for CCS projects 

that are reliant on EOR. The costs 

associated with subpart RR are 

relatively modest, especially in 

comparison with revenues from an EOR 

field. 

After consideration of the variety of 

comments we received on this issue, we 

are confirming our proposal that CCS is 

not an element of the BSER, but it is an 

available compliance measure for a state 

plan. EGUs implementing CCS would 

need to follow reporting requirements 

established in the final CAA section 

111(b) rule for new affected EGUs. 

b. Application of CCU. 

The EPA received comments 

suggesting that carbon capture and 

utilization (CCU) technologies should 

also be allowed as a CO2 emission rate 

adjustment measure for affected EGUs. 

Potential alternatives to storing CO2 in 

geologic formations are emerging and 

may offer the opportunity to offset the 

cost of CO2 capture. For example, 

captured anthropogenic CO2 may be 

stored in solid carbonate materials such 

as precipitated calcium carbonate (PCC) 

or magnesium or calcium carbonate, 

bauxite residue carbonation, and certain 

types of cement through mineralization. 

The carbonate materials produced can 

be tailored to optimize performance in 

specific industrial and commercial 

applications. For example, these 

carbonate materials have been used in 

the construction industry and, more 

recently and innovatively, in cement 

production processes to replace 

Portland cement. 

The Skyonics Skymine® project, 

which opened its demonstration project 

in October 2014, is an example of 

captured CO2 being used in the 

production of carbonate products. This 

plant converts CO2 into commercial 

products. It captures over 75,000 tons of 

CO2 annually from a San Antonio, 

Texas, cement plant and converts the 

CO2 into other products including 

sodium carbonate and sodium 

bicarbonate.902 Other companies— 

including Calera 903 and New Sky 904— 

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 fuelfired 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 working collaboratively 

with stakeholders to evaluate the 

efficacy of alternative utilization 

technologies, to address any regulatory 

hurdles, and to develop appropriate 

monitoring and reporting protocols to 

demonstrate CO2 reductions. 

In the meantime, state plans may 

allow affected EGUs to use qualifying 

CCU technologies to reduce CO2

emissions that are subject to an 

emission standard, or those that are 

counted when demonstrating 

achievement of the CO2 emission 

performance rates or a state rate-based 

or mass-based CO2 emission. State plans 

must include analysis supporting how 

the proposed qualifying CCU technology 

results in CO2 emission mitigation from 

affected EGUs and provide monitoring, 

reporting, and verification requirements 

to demonstrate the reductions. The EPA 

would then review the appropriateness 

and basis for the analysis and the 

verification requirements in the course 

of its review of the state plan. 

c. Application of biomass co-firing 

and repowering. 

The EPA received multiple comments 

supporting the use of biomass 

feedstocks as a means of reducing CO2

emissions within state plans. Several 

commenters also asserted that states 

should be able to determine how 

biomass can be used in their plans. 

Additionally, the EPA received a range 

of comments regarding the valuation of 

CO2 emissions from biomass 

combustion. Some argued that all 

biomass feedstocks should be 

considered ‘‘carbon neutral,’’ while 

others maintained that only the full 

stack emissions from biomass 

combustion should be counted. As 

discussed in the next section, the 

revised Framework for Assessing 

Biogenic Carbon Dioxide for Stationary 

Sources 905 and 2012 Science Advisory 

Board peer review of the 2011 Draft 

Framework find that it is not 

scientifically valid to assume that all 

biogenic feedstocks are ‘‘carbon neutral, 

but that the net biogenic CO2

atmospheric contribution of different 

biomass feedstocks can vary and 

depends on various factors, including 

feedstock type and characteristics, 

production practices, and, in some 

cases, the alternative fate of the 

feedstock.906 Other comments focused 

on the use of sustainably-derived 

agricultural and forest biomass 

feedstocks, including stakeholders who 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64885 

907Specifically, the SAB found that ‘‘There are 

circumstances in which biomass is grown, 

harvested and combusted in a carbon neutral 

fashion but carbon neutrality is not an appropriate 

a priori assumption; it is a conclusion that should 

be reached only after considering a particular 

feedstock’s production and consumption cycle. 

There is considerable heterogeneity in feedstock 

types, sources and production methods and thus 

net biogenic carbon emissions will vary 

considerably.’’ www.epa.gov/climatechange/

ghgemissions/biogenic-emissions.html. 

908Types 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 wasteto-energy facilities. 

909www.whitehouse.gov/sites/default/files/

image/president27sclimateactionplan.pdf. 

910www.epa.gov/climatechange/Downloads/

ghgemissions/US-GHG-Inventory-2015-Chapter-6- 

Land-Use-Land-Use-Change-and-Forestry.pdf. 

supported and those against such 

feedstocks as approvable elements, and 

those who wanted further definition of 

these feedstocks. As discussed above 

and in more detail below, these final 

guidelines provide that states can 

include qualified biomass in their plans 

and include provisions for how 

qualified biomass feedstocks or 

feedstock categories will be determined. 

The EPA will review the 

appropriateness and basis for 

determining qualified biomass 

feedstocks or feedstock categories in its 

review of the approvability of a state 

plan. 

(1) Considerations for use of biomass 

in state plans. 

The EPA recognizes that the use of 

some biomass-derived fuels can play a 

role in controlling increases of CO2

levels in the atmosphere. The use of 

some kinds of biomass has the potential 

to offer a wide range of environmental 

benefits, including carbon benefits. 

However, these benefits can typically 

only be realized if biomass feedstocks 

are sourced responsibly and attributes of 

the carbon cycle related to the biomass 

feedstock are taken into account. 

In November 2014, the agency 

released a second draft of the technical 

report, Framework for Assessing 

Biogenic Carbon Dioxide for Stationary 

Sources. The revised Framework, and 

the EPA’s Science Advisory Board 

(SAB) peer review of the 2011 Draft 

Framework, finds that it is not 

scientifically valid to assume that all 

biogenic feedstocks are ‘‘carbon neutral’’ 

and that the net biogenic CO2

atmospheric contribution of different 

biogenic feedstocks generally depends 

on various factors related to feedstock 

characteristics, production, processing 

and combustion practices, and, in some 

cases, what would happen to that 

feedstock and the related biogenic 

emissions if not used for energy 

production.907 The revised Framework 

also found that the production and use 

of some biogenic feedstocks and 

subsequent biogenic CO2 emissions 

from stationary sources will not 

inevitably result in increased levels of 

CO2 to the atmosphere, unlike CO2

emissions from combustion of fossil 

fuels. 

The SAB peer review panel agreed 

that the use of biomass feedstocks 

derived from the decomposition of 

biogenic waste in landfills, compost 

facilities or anaerobic digesters did not 

constitute a net contribution of biogenic 

CO2 emissions to the atmosphere. And 

further, information considered in 

preparing the second draft of the 

Framework, including the SAB peer 

review and stakeholder input, supports 

the finding that use of waste-derived 

feedstocks 908 and certain forest-derived 

industrial byproducts (such as those 

without alternative markets) are likely 

to have minimal or no net atmospheric 

contributions of biogenic CO2

emissions, or even reduce such impacts, 

when compared with an alternate fate of 

disposal. 

In addition, as detailed in the 

President’s Climate Action Plan,909 part 

of the strategy to address climate change 

includes efforts to protect and restore 

our forests, as well as other critical 

landscapes including grasslands and 

wetlands, in the face of a changing 

climate. This country’s forests currently 

play a critical role in addressing carbon 

pollution, removing more than 13 

percent of total U.S. GHG emissions 

each year.910 Conservation and 

sustainable management can help 

ensure our forests and other lands will 

continue to remove carbon from the 

atmosphere while also improving soil 

and water quality, reducing wildfire risk 

and enhancing forests’ resilience in the 

face of climate change. 

Many states have recognized the 

importance of forests and other lands for 

climate resilience and mitigation, and 

have developed a variety of sustainable 

forestry policies, RE incentives and 

standards, and GHG accounting 

procedures. Some states, for example 

Oregon and California, have programs 

that recognize the multiple benefits that 

forests provide, including biodiversity 

and ecosystem services protection as 

well as 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 high-quality timber while 

considering ecological, economic and 

social values, and the state’s 

Greenhouse Gas Reduction Fund 

provides resources for forestry projects 

to improve forest health, maintain 

carbon storage and avoid GHG 

emissions from pests, wildfires and 

conversion to non-forest uses. 

Several states focus on sustainable 

bioenergy, as seen with the 

sustainability requirements for eligible 

biomass in the Massachusetts RPS, 

which, among other requirements, 

limits old growth forest harvests. Many 

states employ complementary programs 

that together work to address 

sustainable forestry practices. For 

example, Wisconsin uses a state forest 

sustainability framework that provides a 

common system to measure the 

sustainability of the state’s public and 

private forests, in conjunction with a 

series of voluntary best management 

guideline manuals for sustainable 

woody biomass and agriculturallyderived biomass. In addition to statespecific 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 sustainablyderived biomass and sustainable 

forestry and agriculture programs, such 

as the examples highlighted above, may 

help them control increases of CO2

levels in the atmosphere. In addition, 

the EPA’s work on assessing biogenic 

CO2 emissions from stationary sources 

may also help inform states’ efforts to 

assess the role of different biogenic 


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64886 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

911As highlighted in a November 2014 

memorandum to the EPA’s Regional Air Division 

Directors. www.epa.gov/climatechange/

ghgemissions/biogenic-emissions.html. 

912www.epa.gov/sab. 

feedstocks in their plans and broader 

climate strategies.911

The EPA is engaging in a second 

round of targeted peer review on the 

revised Framework with the SAB in 

2015.912 As part of this technical 

process, and as the EPA and states 

implement these emission guidelines, 

the EPA will continue to assess and 

closely monitor overall bioenergy 

demand and associated landscape 

conditions for changes that might have 

negative impacts on public health or the 

environment. 

(2) Additional considerations and 

requirements for biomass fuels. 

The EPA anticipates that some states 

may consider the use of certain biomassderived fuels used in electricity 

generation as a way to control increases 

of CO2 levels in the atmosphere, and 

will include them as part of their state 

plans to meet the emission guidelines. 

Not all forms of biomass are expected to 

be approvable as qualified biomass (i.e., 

biomass that can be considered as an 

approach for controlling increases of 

CO2 levels in the atmosphere). Affected 

EGUs may use qualified biomass in 

order to control or reduce CO2

emissions that are subject to an 

emission standard requirement, or those 

that are counted when demonstrating 

achievement of the CO2 emission 

performance rates or a state rate-based 

or mass-based CO2 emission goal. 

State plan submissions must describe 

the types of biomass that are being 

proposed for use under the state plan 

and how those proposed feedstocks or 

feedstock categories should be 

considered as ‘‘qualified biomass’’ (i.e., 

a biomass feedstock that is 

demonstrated as a method to control 

increases of CO2 levels in the 

atmosphere). The submission must also 

address the proposed valuation of 

biogenic CO2 emissions (i.e., the 

proposed portion of biogenic CO2

emissions from use of the biomass 

feedstock that would not be counted 

when demonstrating compliance with 

an emission standard, or when 

demonstrating achievement of the CO2

emission performance rates or a state 

rate-based or mass-based CO2 emission 

goal). 

With regard to assessing qualified 

biomass proposed in state plans, the 

EPA generally acknowledges the CO2

and climate policy benefits of wastederived biogenic feedstocks and certain 

forest- and agriculture-derived 

industrial byproduct feedstocks, based 

on the conclusions supported by a 

variety of technical studies, including 

the revised Framework for Assessing 

Biogenic Carbon Dioxide for Stationary 

Sources. The use of such waste-derived 

and certain industrial byproduct 

biomass feedstocks would likely be 

approvable as qualified biomass in a 

state plan when proposed with 

measures that meet the biomass 

monitoring, reporting and verification 

requirements discussed below and other 

measures as required elsewhere in these 

emission guidelines. 

Given the importance of sustainable 

land management in achieving the 

carbon goals of the President’s Climate 

Action Plan, sustainably-derived 

agricultural and forest biomass 

feedstocks may also be acceptable as 

qualified biomass in a state plan, if the 

state-supplied analysis of proposed 

qualified feedstocks or feedstock 

categories can adequately demonstrate 

that such feedstocks or feedstock 

categories appropriately control 

increases of CO2 levels in the 

atmosphere and can adequately monitor 

and verify feedstock sources and related 

sustainability practices. Information in 

the revised Framework, the second SAB 

peer review process, and the state and 

third party programs highlighted in the 

previous section can assist states when 

considering the role of qualified 

biomass in state plan submittals. 

Regardless of what biomass feedstocks 

are proposed, state plans must specify 

how biogenic CO2 emissions will be 

monitored and reported, and identify 

specific EM&V, tracking and auditing 

approaches for qualified biomass 

feedstocks. As discussed in section 

VIII.D.2, state plan submittals must 

include CO2 emission monitoring, 

reporting and recordkeeping measures. 

In the case of sustainably-derived forestand agriculture-derived feedstocks, this 

will also include measures for verifying 

feedstock type, origin and associated 

sustainability practices. Section VIII.K 

describes how state plan submittals 

must specify the requirements and 

procedures that EM&V measures must 

meet. As discussed in section VIII.K, the 

EPA is addressing potential EM&V 

measures for qualified biomass in EPA’s 

model trading rule and draft EM&V 

guidance, such as measures that would 

ensure that biomass-related biogenic 

CO2 benefits are quantifiable, verifiable, 

non-duplicative, permanent and 

enforceable. 

State plan submittals must ensure that 

all biomass used meets the state plan 

requirements for qualified biomass and 

associated biogenic CO2 benefits, such 

as using robust, independent third party 

verification and establishing measures 

to maintain transparency, including 

disclosure of relevant documentation 

and reports. State plan submittals must 

include measures for tracking and 

auditing performance to ensure that 

biomass used meets the state plan 

requirements for qualified biomass and 

associated biogenic CO2 benefits. Details 

on how to adjust CO2 rates through the 

use of qualified biomass feedstocks are 

provided in section VIII.K.1. 

The EPA will review the 

appropriateness and basis for proposed 

qualified biomass and biomass 

treatment determinations and related 

accounting, monitoring and reporting 

measures in the course of its review of 

a state plan. The EPA’s determination 

that a state plan satisfactorily proves 

that proposed biomass fuels qualify 

would be based in part on whether the 

plan submittal demonstrates that 

proposed state measures for qualified 

biomass and related biogenic CO2

benefits are quantifiable, verifiable, 

enforceable, non-duplicative and 

permanent. The EPA recognizes that 

CCS technology (described above in 

section VIII.I.2.a) could be applied in 

conjunction with the use of qualified 

biomass. 

(3) Biomass co-firing. 

Affected EGUs may use qualified 

biomass co-fired with fossil fuels at an 

affected EGU. As discussed above in 

this section, not all forms of biomass are 

expected to be approvable and states 

should propose biomass feedstocks and 

treatment of biogenic CO2 emissions in 

state plans, along with supporting 

analysis where applicable. The EPA will 

review the appropriateness and basis for 

such determinations and accounting 

measures in the course of its review of 

a state plan. 

An affected EGU using qualified 

biomass as a fuel must monitor and 

report both its overall CO2 emissions 

and its biogenic CO2 emissions. If 

biomass is to be used as means to 

control increases of CO2 levels in the 

atmosphere in a state plan, the plan 

must specify requirements for reporting 

biogenic CO2 emissions from affected 

EGUs. 

(4) Biomass repowering. 

Affected EGUs could fully repower to 

use primarily qualified biomass. The 

characteristics of affected EGUs, as 

discussed in section IV.D, include the 

use of at least 10 percent fossil fuel for 

applicability of these emission 

guidelines. An EGU repowering with at 

least 90 percent biomass fuels instead of 

fossil fuels becomes a non-affected 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64887 

913For such an EGU to be considered nonaffected, the EGU must be subject to a federally 

enforceable or practically enforceable condition, 

expressed in (for example) a construction permit or 

otherwise, that limits the amount of fossil fuel that 

may be used to 10 percent or less. 

EGU.913 An EGU repowering with less 

than 90 percent biomass would remain 

an affected EGU and therefore need to 

propose biomass feedstocks and 

treatment of biogenic CO2 emissions in 

state plans, along with supporting 

analysis where applicable. 

J. Additional Considerations and 

Requirements for Mass-Based State 

Plans 

This section discusses considerations 

and requirements for different types of 

mass-based state plans. This includes 

mass-based state plans using emission 

budget trading programs, and 

coordination among such programs 

where states retain individual mass CO2

emission goals. CAA section 111(d) 

requires states to submit, in part, a plan 

that establishes standards of 

performance for affected EGUs which 

reflect the BSER. The state plan must be 

satisfactory with respect to this 

requirement in order for the EPA to 

approve the plan. As previously 

described, states meet the statutory 

requirements of 111(d) and the 

requirements of the final emission 

guidelines by establishing emission 

standards for affected EGUs that meet 

the performance rates, which reflect the 

application of BSER as determined by 

the EPA. This final rule allows states to 

alternatively establish emission 

standards that meet rate-based or massbased goals. The state goals must be 

equivalent to the performance rates in 

order to reflect the application of the 

BSER as required by the statute and the 

final emission guidelines. Therefore, a 

state choosing a mass-based 

implementation must address leakage as 

part of its mass-based plan in order to 

satisfactorily establish emission 

standards for affected EGUs that reflect 

the BSER as set by the EPA. 

1. Accounting for CO2 Emission 

Reduction Measures in Mass-Based 

State Plans 

As discussed in section VIII.I, 

measures that occur at affected EGUs 

will result in CO2 emission reductions 

that are automatically accounted for in 

reported CO2 emissions. Other measures 

that provide substitute generation for 

affected EGUs or avoid the need for 

generation from affected EGUs, such as 

demand-side EE, are automatically 

accounted for under a mass-based plan 

to the extent that these measures reduce 

reported CO2 emissions from affected 

EGUs. Unlike under a rate-based plan, 

no additional accounting is necessary in 

order to recognize these emission 

reductions. 

2. Use of Emission Budget Trading 

Programs 

This section addresses the use of 

emission budget trading programs in a 

mass-based state plan, including 

provisions required for such programs 

and the design of such programs in the 

context of a state plan. This includes 

program design approaches that ensure 

achievement of a state mass-based CO2

emission goal (or mass-based CO2 goal 

plus new source CO2 emission 

complement) (section VIII.J.2.b), as well 

as how states can use emission budget 

trading programs with broader source 

coverage and other flexibility features in 

a state plan, such as the programs 

currently implemented by California 

and the RGGI participating states 

(section VIII.J.2.c). Section VIII.J.2.d 

addresses other considerations for the 

design of emission budget trading 

programs that states may want to 

consider, such as allowance allocation 

approaches. Section VIII.J.3 addresses 

multi-state coordination among 

emission budget trading programs used 

in states that retain their individual 

state mass-based CO2 goals. 

a. State plan provisions required for a 

mass-based emission budget trading 

program approach. 

For a mass-based emission trading 

program approach, the state plan would 

include as its federally enforceable 

emission standards requirements that 

specify the emission budget and related 

compliance requirements and 

mechanisms. These requirements would 

include: CO2 emission monitoring, 

reporting, and recordkeeping 

requirements for affected EGUs; 

provisions for state allocation of 

allowances; provisions for tracking of 

allowances, from issuance through 

submission for compliance; and the 

process for affected EGUs to 

demonstrate compliance (allowance 

‘‘true-up’’ with reported CO2 emissions). 

Mass-based emission standards that take 

the form of an emission budget trading 

program must be quantifiable, verifiable, 

enforceable, non-duplicative and 

permanent. These requirements are 

described in more detail at section 

VIII.D.2. 

Where a state plan establishes massbased emission standards for affected 

EGUs only, the emission standards and 

the implementing and enforcing 

measures may be included in the state 

plan as the full set of requirements 

implementing the emission budget 

trading program. Where an emission 

budget trading program in a state plan 

addresses affected EGUs and other fossil 

fuel-fired EGUs or emission sources, 

pursuant to the approaches described in 

sections VIII.J.2.b–d below, the 

requirements that must be included in 

the state plan are the federally 

enforceable emission standards in the 

state plan that apply specifically to 

affected EGUs, and the requirements 

that specifically require affected EGUs 

to participate in and comply with the 

requirements of the emission budget 

trading program. This includes the 

requirement for an affected EGU to 

surrender emission allowances equal to 

reported CO2 emissions, and meet 

monitoring and reporting requirements 

for CO2 emissions, among other 

requirements. These requirements may 

be submitted as part of the federally 

enforceable state plan through 

mechanisms with the appropriate legal 

authority and effect, such as state 

regulations, Title V permit requirements 

for affected EGUs, and other possible 

instruments that impose these 

requirements specifically with respect 

to affected EGUs. Under this approach, 

the full set of regulations establishing 

the emission budget trading program 

that applies to affected EGUs and other 

fossil fuel-fired EGUs and other 

emission sources (if relevant) must be 

described as supporting documentation 

in the state plan submittal for EPA to 

evaluate the approvability of the plan by 

determining whether the affected EGUs 

will achieve the requisite goal. 

b. Requirement for emission budget 

trading programs to address potential 

leakage. 

In Section VII.D, the EPA specifies 

that potential emission leakage must be 

addressed in a state plan with massbased emission standards. The EPA 

received comments suggesting various 

solutions to this concern, such as the 

inclusion of new sources under the rule 

and quantitative adjustments to mass 

CO2 goals for affected EGUs. In response 

to this issue, the EPA has sought to give 

states flexibility in how they meet this 

requirement and base the acceptable 

solutions on what will best suit a state’s 

unique characteristics and state plan 

structure. 

To address the potential for emission 

leakage to new sources under a massbased plan approach, which could 

prevent a mass-based program from 

successfully achieving a mass-based 

CO2 goal consistent with BSER, the EPA 

is requiring that a state submitting a 

plan that is designed to meet a state 

mass-based CO2 goal for affected EGUs 

demonstrate that the plan addresses and 

mitigates the risk of potential emission 

leakage to new sources. The following 


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64888 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

914The first two options need not be mutually 

exclusive; they can both be implemented as part of 

a mass-based plan. 

915 In Table 14, we have provided a mass budget 

for each state that includes the state mass-based 

CO2 goal and a projection for a new source CO2

emission complement. 

916The state mass CO2 goals can be found in 

Table 13 in section VII. 

options provide sufficient 

demonstration that potential emission 

leakage has been addressed in a massbased state plan: 914

1. Regulate new non-affected fossil EGUs 

as a matter of state law in conjunction with 

emission standards for affected EGUs in a 

mass-based plan. If a state adopts an EPAprovided mass budget 915 that includes the 

state mass-based CO2 goal for affected EGUs 

plus a new source CO2 emission 

complement, this option could be 

presumptively approvable. 

2. Use allocation methods in the state plan 

that counteract incentives to shift generation 

from affected EGUs to unaffected fossil-fired 

sources. If a state adopts allowance set-aside 

provisions exactly as they are outlined in the 

finalized model rule, this option could be 

presumptively approvable. 

3. Provide a demonstration in the state 

plan, supported by analysis, that emission 

leakage is unlikely to occur due to unique 

state characteristics or state plan design 

elements that address and mitigate the 

potential for emission leakage. 

In the first option, states may choose 

to regulate new non-affected fossil fuelfired EGUs, as a matter of state law, in 

conjunction with federally enforceable 

emission standards for affected EGUs 

under a mass-based plan. This 

regulation of both new and existing 

sources, as part of a state plan approach, 

is conceptually analogous to a method 

that has been adopted by the mass-based 

systems adopted by California and the 

RGGI participating states. To address 

potential emission leakage under this 

option, the mass-based plan includes 

federally enforceable emission 

standards for affected EGUs, and the 

supporting documentation for the plan 

describes state-enforceable regulations 

for, at a minimum, all new gridconnected fossil fuel-fired EGUs that 

meet the applicability standards for 

EGUs subject to CAA section 111(b). 

States have the option of regulating a 

wider array of sources if they choose, as 

a matter of state law. 

For this option, a state must adopt, as 

a matter of state law, a mass CO2

emission budget of sufficient size to 

cover both affected EGUs under the 

existing source mass CO2 goal provided 

in this final rule, along with sufficient 

CO2 emission tonnage to cover projected 

new sources. There are two pathways 

that states can use for adopting such an 

emission budget that applies to both 

affected EGUs and new sources. The 

EPA is providing a mass budget for each 

state that account for the state’s mass 

CO2 goal for affected EGUs and a 

complementary emission budget for 

new sources, referred to as the new 

source CO2 emission complement. 

States that both adopt the EPA-provided 

mass budget, based on the state massbased CO2 goal for affected EGUs plus 

the new source CO2 emission 

complement, and regulate new sources 

under this emission budget as a matter 

of state law, in conjunction with 

federally enforceable emission 

standards for affected EGUs as part of 

the mass-based state plan may be able 

to submit a presumptively approvable 

plan. Such a plan would include 

federally enforceable emission 

standards for affected EGUs, and in the 

supporting documentation of the plan, 

would describe that the state is 

regulating new sources under a mass 

CO2 emission budget that is equal to or 

less than the state mass-based CO2 goal 

for affected EGUs plus the EPAspecified CO2 emission complement, in 

conjunction with the federally 

enforceable emission standards for 

affected EGUs. If the state plan is 

designed to achieve the EPA provided 

mass budget, plan performance will be 

evaluated based on whether the existing 

affected EGUs, regulated under the 

federally enforceable state plan, and 

new sources regulated as a matter of 

state law, together meet the total mass 

budget that includes the state’s mass 

CO2 goal for affected EGUs and a 

complementary emission budget for 

new sources. 

EPA-specified mass CO2 emission 

budgets for each state, including the 

state’s mass CO2 goal and a new source 

CO2 emission complement, are provided 

in Table 14 below. The derivation of the 

new source CO2 emission complements 

is explained in a TSD titled New Source 

Complements to Mass Goals, which is 

available in the docket. 

TABLE 14—NEW SOURCE COMPLEMENTS TO MASS GOALS

State 

New source 

complements 

(short tons of CO2) 

Mass goals 916 + new source 

complements 

(short tons of CO2) 

Interim Final Interim Final 

Alabama ........................................................................................................... 856,524 755,700 63,066,812 57,636,174 

Arizona ............................................................................................................. 1,424,998 2,209,446 34,486,994 32,380,197 

Arkansas .......................................................................................................... 411,315 362,897 34,094,572 30,685,529 

California .......................................................................................................... 2,846,529 4,413,516 53,873,603 52,823,635 

Colorado .......................................................................................................... 1,239,916 1,922,478 34,627,799 31,822,874 

Connecticut ...................................................................................................... 135,410 119,470 7,373,274 7,060,993 

Delaware .......................................................................................................... 78,842 69,561 5,141,711 4,781,386 

Florida .............................................................................................................. 1,753,276 1,546,891 114,738,005 106,641,595 

Georgia ............................................................................................................ 677,284 597,559 51,603,368 46,944,404 

Idaho ................................................................................................................ 94,266 146,158 1,644,407 1,639,013 

Illinois ............................................................................................................... 818,349 722,018 75,619,224 67,199,174 

Indiana ............................................................................................................. 939,343 828,769 86,556,407 76,942,604 

Iowa ................................................................................................................. 298,934 263,745 28,553,345 25,281,881 

Kansas ............................................................................................................. 260,683 229,997 25,120,015 22,220,822 

Kentucky .......................................................................................................... 752,454 663,880 72,065,256 63,790,001 

Louisiana .......................................................................................................... 484,308 427,299 39,794,622 35,854,321 

Maine ............................................................................................................... 40,832 36,026 2,199,016 2,109,968 

Maryland .......................................................................................................... 170,930 150,809 16,380,325 14,498,436 

Massachusetts ................................................................................................. 225,127 198,626 12,972,803 12,303,372 

Michigan ........................................................................................................... 623,651 550,239 53,680,801 48,094,302 

Minnesota ........................................................................................................ 286,535 252,806 25,720,126 22,931,173 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64889 

TABLE 14—NEW SOURCE COMPLEMENTS TO MASS GOALS—Continued 

State 

New source 

complements 

(short tons of CO2) 

Mass goals 916 + new source 

complements 

(short tons of CO2) 

Interim Final Interim Final 

Mississippi ........................................................................................................ 410,440 362,126 27,748,753 25,666,463 

Missouri ............................................................................................................ 668,637 589,929 63,238,070 56,052,813 

Montana ........................................................................................................... 421,674 653,801 13,213,003 11,956,908 

Nebraska .......................................................................................................... 216,149 190,706 20,877,665 18,463,444 

Nevada ............................................................................................................. 770,417 1,194,523 15,114,508 14,718,107 

New Hampshire ............................................................................................... 71,419 63,012 4,314,910 4,060,591 

New Jersey ...................................................................................................... 313,526 276,619 17,739,906 16,876,364 

New Mexico ..................................................................................................... 527,139 817,323 14,342,699 13,229,925 

New York ......................................................................................................... 522,227 460,753 34,117,555 31,718,182 

North Carolina .................................................................................................. 692,091 610,623 57,678,116 51,876,856 

North Dakota .................................................................................................... 245,324 216,446 23,878,144 21,099,677 

Ohio ................................................................................................................. 949,997 838,170 83,476,510 74,607,975 

Oklahoma ......................................................................................................... 581,051 512,654 45,191,382 41,000,852 

Oregon ............................................................................................................. 453,663 703,399 9,096,826 8,822,053 

Pennsylvania .................................................................................................... 1,257,336 1,109,330 100,588,162 90,931,637 

Rhode Island .................................................................................................... 70,035 61,791 3,727,420 3,584,016 

South Carolina ................................................................................................. 344,885 304,287 29,314,508 26,303,255 

South Dakota ................................................................................................... 46,513 41,038 3,995,462 3,580,518 

Tennessee ....................................................................................................... 358,838 316,598 32,143,698 28,664,994 

Texas ............................................................................................................... 5,328,758 8,516,408 213,419,599 198,105,249 

Utah ................................................................................................................. 981,947 1,522,500 27,548,327 25,300,693 

Virginia ............................................................................................................. 450,039 397,063 30,030,110 27,830,174 

Washington ...................................................................................................... 531,761 824,490 12,211,467 11,563,662 

West Virginia .................................................................................................... 602,940 531,966 58,686,029 51,857,307 

Wisconsin ......................................................................................................... 364,841 321,895 31,623,197 28,308,882 

Wyoming .......................................................................................................... 1,185,554 1,838,190 36,965,606 33,472,602 

Lands of the Navajo Nation ............................................................................. 809,562 1,255,217 25,367,354 22,955,804 

Lands of the Uintah and Ouray Reservation ................................................... 84,440 130,923 2,645,885 2,394,354 

Lands of the Fort Mojave Tribe ....................................................................... 37,162 57,619 648,264 646,138 

Total .......................................................................................................... 33,717,871 41,187,289 1,878,255,620 1,709,291,348 

States can, in the alternative, provide 

their own projections for a new source 

CO2 emission complement to their 

mass-based CO2 goals for affected EGUs. 

In the supporting documentation for the 

state plan submittal, the state must 

specify the new source budget, specify 

the analysis used to derive such a new 

source CO2 emission complement, and 

demonstrate that under the state plan 

affected EGUs in the state will meet the 

state mass-based CO2 goal for affected 

EGUs as a result of being regulated 

under the broader CO2 emission cap that 

applied to both affected EGUs and new 

sources. Such a projection should take 

into account the mass goal 

quantification method outlined in 

section VII.C and the CO2 Emission 

Performance Rate and Goal 

Computation TSD, including the fact 

that the mass-based state goals already 

incorporate a significant growth in 

generation from historical levels. The 

EPA will evaluate the approvability of 

the plan based on whether the federally 

enforceable emission standards for 

affected EGUs in conjunction with the 

state-enforceable regulatory 

requirements for new sources will result 

in the affected EGUs meeting the state 

mass-based CO2 goal. If, rather than 

designing a plan to achieve the EPA 

provided mass budget, the state uses its 

own projections for a new source 

complement and the plan is approved to 

meet this new source complement, plan 

performance will be evaluated based on 

whether the existing affected EGUs, 

regulated under the federally 

enforceable state plan, meet the state’s 

mass CO2 goal for affected EGUs. 

The second demonstration option 

allows states to use allowance allocation 

methods that counteract incentives to 

shift generation from affected EGUs to 

unaffected fossil-fired sources. These 

allocation approaches must be specified 

in state plans as part of the provisions 

for state allocation of allowances 

required under a mass-based plan 

approach (see section VIII.J.2.a). The 

EPA is proposing the inclusion of two 

allocation strategies as part of the massbased approach in the proposed federal 

plan and model rule: Updating outputbased allocations and an allowance setaside that targets RE. These options are 

described in more detail below. If a state 

were to adopt allowance set-aside 

provisions exactly as they are outlined 

in the finalized model rule, they could 

be considered presumptively 

approvable. The allowance allocation 

alternative for addressing leakage was 

chosen for the federal plan and model 

rule proposal because EPA does not 

have authority to extend regulation of 

and federal enforceability to new fossil 

fuel-fired sources under CAA section 

111(d), and therefore we cannot include 

them under a federal mass-based plan 

approach. 

An updating output-based allocation 

method allocates a portion of the total 

CO2 emission budget to affected EGUs 

based, in part, on their level of 

electricity generation in a recent period 

or periods. Therefore, the total 

allocation to an EGU that is eligible to 

receive allowances from an outputbased allowance set-aside is not fixed, 

but instead depends on its generation. 

Under this approach, each eligible 

affected EGU may receive a larger 

allowance allocation if it generates 

more. Therefore, eligible affected EGUs 

will have an incentive to generate more 

in order to receive more allowances, 

aligning their incentive to generate with 

new sources. 

This allocation method can be 

implemented through the creation of a 


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917As specified for the interim plan performance 

period (including specified levels in interim steps 

1 through 3) and the final two-year plan 

performance periods. 

set-aside that reserves a subset of the 

total allowances available to sources, 

and distributes them based upon the 

criteria described above. Because the 

total number of allowances is limited, 

this allocation approach will not exceed 

the overall state mass-based CO2 goal for 

affected EGUs. Instead, it merely 

modifies the distribution of allowances 

in a manner designed to mitigate 

potential emission leakage. 

The other allocation strategy included 

as part of the mass-based approach in 

the proposed federal plan and model 

rule is a set-aside of allowances to be 

allocated to providers of incremental 

RE. A set-aside can also be allocated to 

providers of demand-side EE, or to both 

RE and demand-side EE. The increased 

availability of RE generation can serve 

as another source of generation to satisfy 

electricity demand. Increased demandside EE will reduce the demand that 

sources need to meet. Therefore, both 

RE and demand-side EE can serve to 

reduce the incentive that new sources 

have to generate, and therefore align 

their incentives with affected EGUs. 

Thus, increased RE and demand-side 

EE, supported by a dedicated set-aside, 

can also serve to address potential 

emission leakage. 

If a state is submitting a plan with an 

allocations approach that differs from 

that of the finalized model rule, the state 

should also provide a demonstration of 

how the specified allocation method 

will provide sufficient incentive to 

counteract potential emission leakage. 

Finally, a state can provide a 

demonstration that emission leakage is 

unlikely to occur, without 

implementing either of the two 

strategies above, as a result of unique 

factors, such as the presence of existing 

state policies addressing emission 

leakage or unique characteristics of the 

state and its power sector that will 

mitigate the potential for emission 

leakage. This demonstration must be 

supported by credible analysis. The EPA 

will determine if the state has provided 

a sufficient demonstration that potential 

emission leakage has already been 

adequately addressed, or if additional 

action is required as part of the state 

plan. 

Aside from the possible incentives for 

emission leakage addressed in this 

section, there may be other potential 

generation incentives across states and 

unit subcategories that could increase 

CO2 emissions, particularly in an 

environment where various states are 

implementing a variety of state plan 

approaches in a shared grid region. 

Some examples of these incentives, 

particularly those that were specified by 

commenters, are discussed in section 

VIII.L. That section also describes how 

the EPA has structured this final rule to 

either prevent or minimize the potential 

for foregone emission reductions from 

differential incentives that may result 

from state plan implementation. These 

safeguards include placing restrictions 

on interstate trading when there could 

be a risk of such differential incentives. 

Additionally, the nature of the CO2

emission performance rates and state 

rate-based CO2 goals helps to minimize 

these potential effects, as does the 

MWh-accounting method for adjusting 

the CO2 emission rates of affected EGUs 

under rate-based plans. 

However, without a better 

understanding of the different 

mechanisms that states may ultimately 

choose to meet the emission guidelines, 

and how different requirements in 

different states may interact, the EPA 

cannot project every potential 

differential incentive that could lead to 

a loss of CO2 emission reductions. 

Therefore, once program 

implementation begins, the EPA will 

assess how emission performance across 

states may be affected by the interaction 

of different regulatory structures 

implemented through state plans. Based 

upon that evaluation, the EPA will 

determine whether there are potential 

concerns and what course of action may 

be appropriate to remedy such concerns. 

c. Emission budget trading programs 

that ensure achievement of a state CO2

goal. 

A mass-based emission budget trading 

program can be designed such that 

compliance by affected EGUs will 

achieve the state mass-based CO2 goal. 

Under this approach, a state plan would 

establish CO2 emission budgets for 

affected EGUs during the interim and 

final plan performance periods that are 

equal to or lower than the applicable 

state mass-based CO2 goals specified in 

section VII. A mass-based emission 

budget trading program can also be 

designed such that compliance by 

affected EGUs in conjunction with new 

fossil fuel-fired EGUs meeting 

applicable requirements under state law 

will achieve a mass-based CO2 goal plus 

new source CO2 emission complement. 

Under this approach, a state would 

establish CO2 emission budgets under 

state law for affected EGUs plus new 

sources during the interim and final 

plan performance periods that are equal 

to or lower than the applicable state 

mass-based CO2 emission goal plus the 

new source CO2 emission complement 

specified in Table 14 in section VIII.J.2.b 

above, and describe such emission 

budgets in the supporting 

documentation of the state plan. Under 

either program, compliance periods for 

affected EGUs (or for affected EGUs plus 

new fossil fuel-fired EGUs meeting 

applicable requirements under state 

law) would also be aligned with the 

interim and final plan performance 

periods. This approach would limit total 

CO2 emissions from affected EGUs (or 

total CO2 emissions from affected EGUs 

and new fossil fuel-fired EGUs meeting 

applicable requirements under state 

law) during the interim and final plan 

performance periods to an amount equal 

to or less than the state’s mass-based 

CO2 goal (or mass-based CO2 goal plus 

new source CO2 emission complement). 

Under this approach, compliance by 

affected EGUs with the mass-based 

emission standards in a plan would 

ensure that the state achieves its massbased CO2 goal for affected EGUs (or 

mass-based CO2 goal plus new source 

CO2 emission complement). No further 

demonstration would be necessary by 

the state to demonstrate that its plan 

would achieve the state’s mass-based 

CO2 goal (or mass-based CO2 goal plus 

new source CO2 emission complement). 

For this type of plan, where the 

emission budget is equal to or less than 

the state mass CO2 goal (or mass-based 

CO2 goal plus new source CO2 emission 

complement),917 the EPA would assess 

achievement of the state goal based on 

compliance by affected EGUs with the 

mass-based emission standards, rather 

than reported CO2 emissions by affected 

EGUs during the interim plan 

performance periods and final plan 

performance periods. This approach 

would allow for allowance banking 

between performance periods, including 

the interim and final performance 

periods outlined in this final rule. 

Banking provisions have been used 

extensively in rate-based environmental 

programs and mass-based emission 

budget trading programs. This is 

because banking reduces the cost of 

attaining the requirements of the 

regulation. The EPA has determined 

that the same rationale and outcomes 

apply under a CO2 emission rate 

approach, in that allowing banking will 

reduce compliance costs. Banking 

encourages additional emission 

reductions in the 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. 

It is also beneficial when addressing 

pollutants that are long-lived in the 

atmosphere, such as CO2, and where 

increasing atmospheric concentration of 


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918Section VIII.J.2.a describes how state plan 

submittals must include as requirements, or 

describe as part of supporting documentation, 

relevant aspects of such emission budget trading 

programs. 

919This approach for establishing federally 

enforceable emission standards based on 

requirements for affected EGUs subject to a broader 

emission budget trading program that also covers 

non-affected emission sources is addressed in 

section VIII.J.2.d. above. 

920For 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. 

921A demonstration of how a plan will achieve 

a state’s rate-based or mass-based CO2 goal (or massbased CO2 goal plus new source CO2 emission 

complement) is one of the required plan 

components, as described in section VIII.D.2. 

922Achievement 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 

Continued 

the pollutant leads to increasing adverse 

atmospheric impacts. 

Banking also provides long-term 

economic signals to affected emission 

sources and other market participants 

where actions taken today will have 

economic value in helping meet tighter 

emission constraints in the future, 

provided those emission sources expect 

that the banked ERCs or emission 

allowances may be used for compliance 

in the future. Linking short-term and 

long-term economic incentives, which 

allows owners or operators of affected 

EGUs and other market participants to 

assess both short-term and long-term 

incentives when making decisions about 

compliance approaches or emission 

reduction investments, reduces longterm compliance costs for affected EGUs 

and ratepayer impacts. In addition, the 

increased temporal flexibility provided 

by banking would further help address 

potential electric reliability concerns, as 

banked ERCs can be used to meet 

emission standard requirements for an 

affected EGU. 

d. Addressing emission budget trading 

programs with broader source coverage 

and other flexibility features. 

As described in section VIII.C above, 

under the emission standards plan type, 

a mass-based emission budget trading 

program with broader source coverage 

and other flexibility features may be 

designed such that compliance by 

affected EGUs (or compliance by 

affected EGUs plus new fossil fuel-fired 

EGUs meeting applicable requirements 

under state law) would assure 

achievement of the applicable state 

mass-based CO2 goal (or mass-based CO2

goal plus new source CO2 emission 

complement).918

However, emission budget trading 

programs, including those currently 

implemented by California and the 

RGGI participating states, include a 

number of different design elements that 

functionally expand the emission 

budget under certain circumstances. If a 

state chose, it could apply such massbased emission standards, in the form of 

an emission budget trading program that 

differs in design from that outlined in 

section VIII.J.2.c above. These types of 

emission budget trading programs must 

be submitted as a part of a state 

measures plan type. Where an emission 

budget trading program addresses 

affected EGUs and other fossil fuel-fired 

EGUs, the requirements that must be 

included in the state plan are the 

federally enforceable emission 

standards in the state plan that apply 

specifically to affected EGUs, and the 

requirements that specifically require 

affected EGUs to participate in and 

comply with the requirements of the 

emission budget trading program. This 

includes the requirement for an affected 

EGU to surrender emission allowances 

equal to reported CO2 emissions, and 

meet monitoring and reporting 

requirements for CO2 emissions, among 

other requirements. These requirements 

may be submitted as part of the 

federally enforceable state plan through 

mechanisms with the appropriate legal 

authority and effect, such as state 

regulations, relevant Title V permit 

requirements for affected EGUs, and 

other possible instruments that impose 

these requirements specifically with 

respect to affected EGUs.919 Under this 

approach, the full set of regulations 

establishing the emission budget trading 

program that applies to affected EGUs 

and other fossil fuel-fired EGUs and 

other emission sources (if relevant) must 

be described as supporting 

documentation in the state plan 

submittal. This structure is appropriate 

to ensure that states with an emission 

budget trading program that addresses 

both affected EGUs and other fossil fuelfired EGUs do not inappropriately 

submit requirements regarding entities 

other than affected EGUs for inclusion 

in the federally enforceable state plan. 

Such state programs could include a 

number of different design elements. 

This includes broader program scope, 

where a program includes other 

emission sources beyond affected EGUs 

subject to CAA section 111(d) and new 

fossil fuel-fired EGUs, such as industrial 

sources. Programs might also include 

design elements that make allowances 

available in addition to the established 

emission budget. This includes projectbased 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.920

In the case where an emission budget 

trading program contains elements that 

functionally expand the emission 

budget in certain circumstances, 

compliance by affected EGUs with the 

mass-based emission standards would 

not necessarily ensure that CO2

emissions from affected EGUs do not 

exceed the state’s mass-based CO2 goal 

(or mass-based CO2 goal plus new 

source CO2 emission complement). 

However, states could modify such 

programs to remove flexibility 

mechanisms that functionally expand 

the emission budget, such as out-ofsector offsets and certain cost 

containment reserve mechanisms, and 

submit the program under an emission 

standards plan type. 

Where a state chooses to retain such 

flexibility mechanisms as part of an 

emission budget trading program, the 

program may only be implemented as 

part of a state measures plan type 

because these state flexibility 

mechanisms would not assure CO2

emissions from affected EGUs do not 

exceed the state’s mass-based CO2 goal 

(or mass-based CO2 goal plus new 

source CO2 emission complement). A 

description of the state measures plan 

type and related requirements is 

provided in section VIII.C.3. 

Under this type of approach, the state 

would be required to include a 

demonstration,921 in its state plan 

submittal, of how its state measures, in 

conjunction with any emission 

standards on affected EGUs, would 

achieve the state mass-based CO2 goal 

(or mass-based CO2 goal plus new 

source CO2 emission complement). This 

demonstration would include a 

projection of the total CO2 emissions 

from the fleet of affected EGUs that 

would occur as a result of compliance 

with the emission standards in the plan. 

Section VIII.D.2 discusses how such 

demonstrations could address design 

elements of emission budget trading 

programs with broader scope and 

additional compliance flexibility 

mechanisms, such as those included in 

the California and RGGI programs. Once 

the plan is implemented, if the massbased CO2 goal is not achieved during 

a plan performance period, the backstop 

federally enforceable emission 

standards included in the state plan that 

apply to affected EGUs would be 

implemented, as described in section 

VIII.C.3.b.922


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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. 

923Allowance allocation refers to the methods 

used to distribute CO2 allowances to the owners or 

operators of affected EGUs and/or other market 

participants. 

924The emission standards in each individual 

state plan must include requirements that address 

the issuance of CO2 allowances and tracking of CO2

allowances from issuance through use for 

compliance. The description here addresses how 

those requirements will be implemented through 

the use of a joint tracking system, interoperable 

tracking systems, or an EPA-administered tracking 

system. 

925The EPA would designate tracking systems 

that it has determined adequately address the 

integrity elements necessary for the issuance and 

tracking of emission allowances. Under this 

approach, a state could include in its plan such a 

designated tracking system, which has already been 

reviewed by the EPA. 

e. Considerations for mass-based 

emission budget trading programs. 

The EPA notes that while an emission 

budget trading program included in an 

emission standards plan must be 

designed to achieve a state mass-based 

CO2 goal (or mass-based CO2 goal plus 

new source CO2 emission complement), 

states have wide discretion in the design 

of such programs, provided the 

emission standards included in the plan 

are quantifiable, verifiable, enforceable, 

non-duplicative, and permanent. 

(1) Allowance allocation. A key 

example is state discretion in the CO2

allowance allocation methods included 

in the program.923 This includes the 

methods used to distribute CO2

allowances and the parties to which 

allowances are distributed. For example, 

if a state chose, it could include CO2

allowance allocation provisions that 

provide incentives for certain types of 

complementary activities, such as RE 

generation, that help achieve the overall 

CO2 emission limit for affected EGUs 

established under the program. In 

addition, a state could use its allocation 

provisions to encourage investments in 

RE and demand-side EE in low-income 

communities. States could also use CO2

allowance allocation provisions to 

provide incentives for early action, such 

as RE generation or demand-side EE 

savings that occur prior to the beginning 

of the interim plan performance period 

in 2022. For example, a state could 

include CO2 allowance allocation 

provisions where CO2 allowances are 

distributed to RE generators based on 

MWh of RE generation that occurs prior 

to 2022. Such provisions might be 

addressed through a finite set-aside of 

CO2 allowances that are available for 

allocation under these provisions. This 

set-aside could be additional to a setaside created by the state for the CEIP 

discussed in section VIII.B.2. 

(2) Facility-level compliance. If a state 

chose, it could evaluate compliance 

(i.e., allowance true-up) under its 

emission budget trading program at the 

facility level, rather than at the 

individual unit level. The EPA has 

adopted facility-level compliance in the 

emission budget-trading programs it 

administers, including the Acid Rain 

Program (70 FR 25162), Clean Air 

Interstate Rule (70 FR 25162), and 

Cross-State Air Pollution Rule (76 FR 

48208). Under this approach, states 

would still track reported unit-level CO2

emissions—while evaluating 

compliance at the facility level— 

allowing them to track increases and 

decreases of CO2 emissions at 

individual EGUs. 

3. Multi-state coordination: Massbased 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 requirements that enable 

affected EGUs to use allowances issued 

in other states for compliance under the 

state’s emission budget trading program. 

This type of state plan must also 

indicate how CO2 allowances will be 

tracked from issuance through use for 

compliance, through either a joint 

tracking system, interoperable tracking 

systems, or use of an EPA-administered 

tracking system.924

Two different implementation 

approaches could be used to create such 

links. A state could submit a ‘‘ready-forinterstate-trading’’ plan using an EPAapproved tracking system, but the plan 

would not identify links with other 

states. A state could also submit a plan 

with specified bilateral or multilateral 

links that explicitly identify partner 

states. 

Interstate allowance linkages would 

not affect the approvability of each 

state’s individual plan. However, 

different considerations apply for the 

approvability of an individual plan with 

such links, based on whether the 

emission budget trading program in the 

plan applies only to affected EGUs or 

includes other emission sources, and if 

the plan is designed to meet a state 

mass-based CO2 goal for affected EGUs 

only or to meet a mass-based CO2 goal 

plus a new source CO2 emission 

complement). 

Under the first ‘‘ready-for-interstatetrading’’ implementation approach, a 

state would indicate in its state plan 

that its emission budget trading program 

will be administered using an EPAapproved (or EPA-administered) 

emission and allowance tracking 

system.925 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 EPAapproved tracking system. The state 

would also indicate in the regulatory 

provisions for its emission budget 

trading program that it would recognize 

as usable for compliance any emission 

allowance issued by any other state with 

an EPA-approved state plan that also 

uses the specified EPA-approved 

tracking system. 

States could also adopt such a 

collaborative emission trading approach 

over time (through appropriate state 

plan revisions if the plan is not already 

structured as ready-for-interstatetrading), without requiring all of the 

original participating states to revise 

their EPA-approved plans. 

Under the second implementation 

approach, a state could specify the other 

states from which it would recognize 

issued emission allowances as usable 

for compliance with its emission budget 

trading program. The state would 

indicate in the regulatory provisions for 

its emission budget trading program that 

emission allowances issued in other 

identified partner states may be used by 

affected EGUs for compliance. Such 

plans must indicate how allowances 

will be tracked from issuance through 

use for compliance, through either a 

joint tracking system, interoperable 

tracking systems, or EPA-administered 

tracking system. The EPA would assess 

the design and functionality of this 

tracking system(s) when reviewing 

individual submitted state plans. 

Under this approach, states could also 

join such a collaborative emission 

trading approach over time. However, 

all participating states would need to 

revise their EPA-approved plans. If the 

expanded linkage is among previously 

approved 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 


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926 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. 

927Compliance 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. 

928This approach is warranted because under 

such linked programs, CO2 emissions from affected 

EGUs in one state that exceed a state’s mass CO2

goal (or mass-based CO2 goal plus new source CO2

emission complement) would be accompanied by 

CO2 emissions from affected EGUs in another 

linked state that are below that state’s mass CO2

goal (or mass-based CO2 goal plus new source CO2

emission complement). 

929This may apply under both an emission 

standards plan and a state measures plan. Section 

VIII.J.2.a describes how state plan submissions must 

include as requirements, or describe as part of 

supporting documentation, relevant aspects of such 

emission budget trading programs. 

930Under a program that applies to affected EGUs 

and other emission sources, compliance by affected 

EGUs with the emission standard—a requirement to 

surrender emission allowances equal to reported 

emissions—will not assure that a state’s CO2 mass 

goal (or mass-based CO2 goal plus new source CO2

emission complement) is achieved. As a result, a 

further demonstration is required in the plan that 

compliance by affected EGUs with the program will 

result in CO2 emissions from affected EGUs that are 

at or below a state’s CO2 mass goal (or mass-based 

CO2 goal plus new source CO2 emission 

complement). 

931Section VIII.J.2.a describes how state plan 

submittals must include as requirements, or 

describe as part of supporting documentation, 

relevant aspects of such emission budget trading 

programs. 

in order to maintain the integrity of the 

linked programs.926

a. Considerations for linked emission 

budget trading programs. 

For individually submitted plans, 

interstate emission allowance linkages 

would not affect the approvability of 

each state’s plan. However, 

approvability of an individual linked 

plan would differ based on the structure 

of the emission budget trading program 

included in the plan. These differences 

for plan approvability address 

distinctions among programs that 

include only affected EGUs and 

programs that cover a broader set of 

emission sources, as well as if the plan 

is designed to meet a state mass-based 

CO2 goal for affected EGUs only or to 

meet a mass-based CO2 goal plus a new 

source CO2 emission complement. 

Differences in approval criteria are 

necessary to ensure that each individual 

state plan demonstrates it will achieve 

a state’s mass-based CO2 emission goal 

for affected EGUs (or mass-based CO2

goal plus new source CO2 emission 

complement). The accounting applied to 

individual plans to assess whether a 

state achieves its mass-based CO2 goal 

(or mass-based CO2 goal plus new 

source CO2 emission complement) will 

also differ, based on whether an 

emission budget trading program 

includes only affected EGUs (or affected 

EGUs and applicable new fossil fuelfired EGUs) or a broader set of emission 

sources. These considerations are 

addressed below, for both types of 

emission budget trading programs. 

(1) Links among emission budget 

trading programs that only include 

affected EGUs or affected EGUs and 

applicable new fossil fuel-fired EGUs. 

Where the emission budget trading 

programs in each plan apply only to 

affected EGUs subject to the final rule 

(or emission budget trading programs 

that apply to affected EGUs under the 

state plan and applicable new fossil 

fuel-fired EGUs under state law), and 

include compliance timeframes for 

affected EGUs that align with the 

interim and final plan performance 

periods, both plans would functionally 

be meeting an aggregated multi-state 

mass-based goal (or aggregated massbased CO2 goal plus new source CO2

emission complement), but without 

formally aggregating the goal (or 

aggregated mass-based CO2 goal plus 

new source CO2 emission complement). 

CO2 emissions from affected EGUs in 

both states could not exceed the total 

combined CO2 emission budgets under 

the emission standards in the two states. 

A net ‘‘import’’ of CO2 allowances from 

one state would mean that allowable 

CO2 emissions in the other net 

‘‘exporting’’ state are less than that 

state’s established emission budget. On 

a multi-state basis, CO2 emissions from 

affected EGUs could not exceed the sum 

of the states’ emission budgets. 

Under this approach, if the emission 

budget for the mass-based emission 

standard in each plan is equal to or 

lower than the state’s mass-based CO2

goal (or aggregated mass-based CO2 goal 

plus new source CO2 emission 

complement, if applicable), compliance 

by affected EGUs with the mass 

emission standard in a state 927 would 

ensure that cumulatively the mass CO2

goals (or mass-based CO2 goals plus new 

source CO2 emission complements) of 

the linked states are achieved. As a 

result, achievement of an individual 

state’s mass CO2 goal (or mass-based 

CO2 goal plus new source CO2 emission 

complement) would be assessed by the 

EPA based on compliance by affected 

EGUs with the mass-based emission 

standards in the state plan, rather than 

reported CO2 emissions by affected 

EGUs in the state.928

The same accounting approach will 

apply for such plans in all cases, even 

if the state is linked to another state 

emission budget trading program that 

includes a broader set of emission 

sources (e.g., sources beyond affected 

EGUs, or beyond affected EGUs plus 

applicable new fossil fuel-fired EGUs), 

as described below. In all cases, where 

a state plan includes an emission budget 

trading program that applies only to 

affected EGUs (or beyond affected EGUs 

plus applicable new fossil fuel-fired 

EGUs), and includes compliance 

timeframes that align with plan 

performance periods, achievement of a 

state mass CO2 goal (or mass-based CO2

goal plus new source CO2 emission 

complement) will be assessed by the 

EPA based on whether affected EGUs 

comply with the mass-based emission 

standard, rather than reported CO2

emissions from affected EGUs. 

(2) Links with emission budget trading 

programs that include a broader set of 

emission sources. State plans may 

involve emission budget trading 

programs that include affected EGUs, 

applicable new fossil fuel-fired EGUs if 

a plan includes a new source CO2

emission complement, and other nonaffected emission sources.929

Generally, such plans must 

demonstrate that the mass-based CO2

goal for affected EGUs (or mass-based 

CO2 goal plus new source CO2 emission 

complement) in a state will be achieved, 

as a result of implementation of the 

emission budget trading program.930

Where a program includes other nonaffected emission sources (i.e., nonaffected emission sources that are not 

subject to a new source CO2 emission 

complement) and is linked with other 

programs,931 the state plan submittal 

must include a demonstration that the 

mass-based CO2 goal (or mass-based CO2

goal plus new source CO2 emission 

complement) will be achieved, 

considering the emission allowance 

links with other programs. The EPA, in 

determining the approvability of each 

state’s plan under this approach, would 

evaluate the linkages between plans. 

Specifically, the EPA would evaluate 

whether the linkages would enable the 

affected EGUs (or affected EGUs in 

conjunction with applicable new fossil 

fuel-fired EGUs) in each participating 

state to meet the state’s applicable massbased CO2 goal (or mass-based CO2 goal 

plus new source CO2 emission 

complement). 

During plan implementation, the EPA 

would assess whether the affected EGUs 

in a state achieved the state’s massbased CO2 goal (or mass-based CO2 goal 

plus new source CO2 emission 

complement) as follows. Reported CO2


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932A 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 non-affected 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. 

933Compliance 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. 

934ERCs may be issued for the measures 

presented in this section, as well as to affected 

EGUs that emit at a CO2 emission rate below their 

assigned emission rate limit. ERC issuance and 

trading is discussed in detail in section VIII.K.2. 

That section addresses the accounting method for 

ERC issuance to affected EGUs that perform below 

their assigned CO2 emission rate. 

emissions from affected EGUs under 

such plans must be at or below a state’s 

mass-based CO2 emission goal (or massbased CO2 goal plus new source CO2

emission complement) during an 

identified plan performance period, 

with the following state accounting 

adjustments for net ‘‘import’’ and net 

‘‘export’’ of CO2 allowances: 

• Net ‘‘imports’’ of CO2 allowances: 

Reported CO2 emissions from affected EGUs 

in a state may exceed the state CO2 mass goal 

(or mass-based CO2 goal plus new source CO2

emission complement) during an identified 

plan performance period in the amount of an 

adjustment for the net ‘‘imported’’ CO2

allowances during the plan performance 

period. The adjustment represents the CO2

emissions (in tons) equal to the number of 

net ‘‘imported’’ CO2 allowances. Under this 

adjustment, such allowances must be issued 

by a state with an emission budget trading 

program that only applies to affected EGUs 

(or affected EGUs plus applicable new fossil 

fuel-fired EGUs). Net ‘‘imports’’ of 

allowances are determined through review of 

tracking system compliance accounts. 

• Net ‘‘exports’’ of CO2 allowances: 

Reported CO2 emissions from affected EGUs 

in a state during an identified plan 

performance period must be equal to or less 

than the CO2 mass goal (or mass-based CO2

goal plus new source CO2 emission 

complement) minus an adjustment for the 

‘‘exported’’ CO2 allowances during the plan 

performance period. The adjustment 

represents CO2 emissions (in tons) equal to 

the number of net ‘‘exported’’ CO2

allowances. Net ‘‘exports’’ of allowances are 

determined through review of tracking 

system compliance accounts. 

Where CO2 emissions from affected 

EGUs exceed these levels (based on 

reported CO2 emissions with applied 

plus or minus adjustments for net CO2

allowance ‘‘imports’’ or ‘‘exports’’) over 

the 8-year interim period or during any 

final plan reporting period, or by 10 

percent or more during the interim step 

1 or step 2 periods, a state would be 

considered to, in the case of the interim 

and final periods, not have met its CO2

mass goal during an identified plan 

performance period, and in the case of 

the interim step periods, to not be on 

course to meet the final goal. As a result, 

under a state measures state plan, 

implementation of the backstop 

federally enforceable emission 

standards for affected EGUs in the state 

plan would be triggered. 

A net transfer of CO2 allowances 

during a plan performance period 

represents the net number of CO2

allowances (issued by a respective state) 

that are transferred from the compliance 

accounts of affected EGUs in that state 

to the compliance accounts of affected 

EGUs in another state.932 This net 

transfer is determined based on 

compliance account holdings at the end 

of the plan performance period.933 For 

example, assume two states, State A and 

State B, with emission budgets of 1,000 

tons of CO2. Each state issues 1,000 CO2

allowances. At the end of a plan 

performance period, affected EGUs in 

State A collectively hold 500 CO2

allowances in their compliance 

accounts that were issued by State A. 

Affected EGUs in State B collectively 

hold in their compliance accounts 500 

CO2 allowances issued by State A and 

1,000 CO2 allowances issued by State B. 

In this simplified example, a net transfer 

of 500 CO2 allowances has occurred 

between State A and State B. State A has 

‘‘exported’’ 500 CO2 allowances to State 

B, while State B has ‘‘imported’’ 500 

CO2 allowances from state A. 

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 ratebased emission standard, or when a 

state is demonstrating achievement of 

the CO2 emission performance rates or 

applicable rate-based state CO2 emission 

goal in the emission guidelines. This 

section also discusses requirements for 

state plans that include rate-based 

emission trading programs, including 

approaches and requirements for 

coordination among such programs 

where states retain individual state ratebased CO2 emission goals. 

1. Adjustments to CO2 Emission Rates in 

Rate-Based State Plans 

Section VIII.K.1.a below describes the 

basic accounting method for adjusting a 

CO2 emission rate, as well as eligibility 

requirements for measures that may be 

used for adjusting a CO2 emission rate. 

Section VIII.K.1.b addresses measures 

that may not be used to adjust the CO2

emission rate of an affected EGU in a 

state plan, and explains the basis for 

this exclusion. Section VIII.K.1.c 

addresses measures that reduce CO2

emissions outside the electric power 

sector. Such measures may not be 

counted under either a rate-based or 

mass-based state plan. 

a. Measures taken to adjust the CO2

emission rate of an affected EGU. This 

section describes how measures that 

substitute for generation from affected 

EGUs or avoid the need for generation 

from affected EGUs may be used in a 

state plan to adjust the CO2 emission 

rate of an affected EGU. This section 

discusses the required accounting 

method for adjusting a CO2 emission 

rate, as well as general eligibility 

requirements that apply to different 

categories of measures that may be used 

to adjust a CO2 emission rate. Where 

relevant, this section also discusses 

additional specific accounting methods 

and other relevant requirements that 

apply to different categories of 

measures. 

A CO2 emission rate adjustment may 

be applied in different rate-based state 

plan contexts. For example, in a ratebased emission trading program, 

adjustments may be applied through the 

use of ERCs.934 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 ratebased emission standard and/or 

demonstrate achievement of a state CO2

rate-based emissions goal. All of the 

measures described in this section will 

substitute for generation from affected 

EGUs or avoid the need for generation 


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935These requirements are discussed in section 

VIII.D. 

936Requirements for the issuance of ERCs and a 

further discussion of how ERCs are used in 

compliance with rate-based emission limits are 

addressed in section VIII.K.2. 

937Any ERCs used to adjust a CO2 emission rate 

must meet requirements in the emission guidelines. 

938For a detailed discussion of this method, see 

Section VI.C.3. Form of the Performance Rates, in 

the Equation section. 

from affected EGUs, thereby reducing 

CO2 emissions. This includes 

incremental NGCC and 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 RE imports connected to 

the grid in the contiguous U.S., as 

discussed elsewhere in this preamble. 

The EPA believes that the broad 

categories of measures listed in this 

section address the wide range of 

actions that are available to reduce CO2

emissions from affected EGUs under a 

rate-based state plan. However, the 

actions that a state could include in a 

rate-based state plan are not necessarily 

limited to those described in this 

section. Other specific actions not listed 

here may be incorporated in a state 

plan, provided they meet the general 

eligibility requirements listed in this 

section, as well as the other relevant 

requirements in the emission 

guidelines.935 Nor are states required to 

include in their plans all of the actions 

that are described in this section. 

This section discusses the basic 

accounting method for adjusting the 

reported CO2 emission rate of an 

affected EGU, through the use of 

measures that substitute for or avoid 

generation from affected EGUs. That 

method is based on adding MWh from 

such measures to the denominator of an 

affected EGU’s reported CO2 emission 

rate (lb CO2/MWh). Those additional 

MWh are based on quantified and 

verified electricity generation or 

electricity savings from eligible 

measures, and in the case of an affected 

EGU’s compliance with its emission 

standard, are reflected in ERCs. This 

section also addresses eligibility 

requirements for resources that are used 

to adjust an affected EGU’s CO2

emission rate. 

(1) General accounting approach for 

adjusting a CO2 emission rate. 

In this final rule, the reported CO2

emission rate of an affected EGU may be 

adjusted based on quantified and 

verified MWh from qualifying zeroemitting 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 zeroor low-emitting 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-side EE and DSM). In 

both of these cases, generation from an 

affected EGU is replaced, through 

substitute generation or a reduction in 

electricity demand. To the extent that 

qualifying zero-emitting and lowemitting 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’s CO2 emission rate allows 

mass CO2 emission reductions from 

these measures to be fully reflected in 

an adjusted CO2 emission rate. 

The following provides a simple 

calculation example of how MWh of 

replacement generation added to the 

denominator of an affected EGU’s 

reported CO2 emission rate results in a 

lower adjusted CO2 emission rate. 

Assume an affected EGU with CO2

emissions of 200,000 lb and electric 

generation of 100 MWh during a 

reporting period. The affected EGU’s 

reported CO2 emission rate is 2,000 lb/ 

MWh (200,000 lb CO2/100 MWh = 2,000 

lb/MWh). When complying with its 

rate-based emission limit, the affected 

EGU submits 10 ERCs, representing 10 

MWh of replacement generation.936

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.937 The CO2 emission 

performance rates or rate-based CO2 goal 

in the emission guidelines are met if the 

adjusted CO2 emission rate of affected 

EGUs in a state is at or below the 

specified CO2 emission rate in a state 

plan that applies for an identified plan 

performance period. 

Numerous commenters requested that 

the EPA ensure consistency between 

goal-setting calculations and the 

methodology used to demonstrate 

achievement of a CO2 emission rate 

under a state plan. This approach for 

adjusting a CO2 emission rate 

corresponds with how RE, one of the 

components 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.938

When demonstrating achievement of a 

CO2 emission performance rate, the 

reported CO2 emissions already reflect 

the actual emission reductions from the 

deployment of qualifying zero-emitting 

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 rate-based CO2 goals in the 

emission guidelines, the zero-emitting 

MWhs (from substitute generation or a 

reduction in electricity demand) must 

still be added to the denominator of a 

reported CO2 emission rate to calculate 

an adjusted CO2 emission rate that 

appropriately reflects the replaced 

generation. Thus, the resultant rate, 

where the numerator reflects CO2

emission reductions from qualifying 

measures, and the denominator reflects 

replaced generation, is consistent with 

the goal-setting calculation. 

Several commenters suggested that 

the EPA consider the regional nature of 

the electricity grid and how RE and 

demand-side EE impacts generation and 

CO2 emissions across the grid when 

accounting for the impacts of RE and 


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939For 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. 

940Similarly, as discussed in section 

VIII.C.2.b.(2).(a), allowances may be banked in a 

mass-based trading program. 

demand-side EE measures in a ratebased plan approach. This MWh 

accounting structure corresponds with 

the regional treatment of RE resources in 

the BSER that provide substitute 

generation in the EPA-calculated CO2

emission performance rates in the 

emission guidelines. Consistent with 

assumptions used in calculating the CO2

emission performance rates in the 

emission guidelines, affected EGUs and 

states can take full credit for the MWh 

resulting from eligible measures they are 

responsible for deploying, no matter 

where those measures are implemented. 

CO2 emission reductions from the 

eligible measures may occur across the 

region; however, an affected EGU or a 

state may only take credit for avoided 

CO2 emissions at that affected EGU or 

set of EGUs in question, as reflected in 

the reported stack CO2 emissions of 

affected EGUs. 

Because of the separate accounting of 

MWhs and CO2 emissions, with 

emission impacts inherent in reported 

stack CO2 emissions and zero-emitting 

MWh impacts requiring explicit 

adjustments, the accounting method 

corresponds with the use of MWhdenominated ERCs in the rate-based 

emission trading framework specified in 

this rule. The accounting method only 

requires a quantification of the MWh 

generated or avoided by an eligible 

measure, and thus credits or 

adjustments can be denominated in 

MWh and do not need to represent an 

approximation of the CO2 emission 

reductions that result from those MWhs. 

This creates a crediting system or rate 

adjustment process that is simpler to 

implement than one that requires an 

approximation of avoided CO2

emissions. 

The MWh accounting method also 

creates a crediting system or rate 

adjustment process that is indifferent to 

the rate-based CO2 emission goals of 

individual states, or the specific CO2

emission rate standards that states may 

apply, and the relative stringency of 

those goals or standards. Use of ERCs in 

rate-based emission trading programs is 

addressed in detail in section VIII.K.2. 

As a result, the MWh accounting 

method addresses interstate effects, 

because it inherently accounts for how 

generation replacement and CO2

emission reduction impacts may cross 

state borders. For example, if the 

accounting method was informed by 

avoided CO2 emission rates, it could 

create perverse incentives for 

development of zero- or low-emitting 

resources in states that result in the 

greatest calculated estimate of CO2

emission reductions for each 

replacement MWh. Instead, this 

accounting method is indifferent to 

avoided CO2 emission rates and creates 

the same number of zero-emitting 

credits or adjustment for each MWh of 

energy generation or savings, wherever 

they occur. For a detailed discussion on 

how the accounting method addresses 

interstate effects, see section VIII.L. 

(2) General eligibility requirements for 

resources used to adjust a CO2 emission 

rate. 

The EPA is finalizing certain general 

eligibility requirements for resources 

used to adjust a CO2 emission rate. 

These requirements align eligibility 

with certain factors and assumptions 

used in establishing the BSER, and by 

extension, application of the BSER to 

the performance levels established for 

affected EGUs in the emission 

guidelines, as well as state rate and 

mass CO2 goals. As a result, the 

requirements ensure that measures that 

may be used in a state plan are treated 

consistently (to the extent possible) with 

the EPA’s assessment of the BSER.939

These general requirements also address 

potential interactions among rate and 

mass plans, as discussed more fully in 

section VIII.L. 

As discussed in the sections that 

follow, the general eligibility criteria 

address: 

• The date from which eligible measures 

may be installed (e.g., installation of RE 

generating capacity and installation of EE 

measures); 

• the date from which MWh from eligible 

measures may be counted, and applied 

toward adjusting a CO2 rate; and 

• the need to demonstrate that eligible 

measures replace or avoid generation from 

affected EGUs. 

(a) Eligibility date for installation of 

RE/EE and other measures and MWh 

generation and savings. 

Incremental emission reduction 

measures, such as RE and demand-side 

EE, can be recognized as part of state 

plans, but only for the emission 

reductions they provide during a plan 

performance period. Specifically, this 

means that measures installed in any 

year after 2012 are considered eligible 

measures under this final rule, but only 

the quantified and verified MWh of 

electricity generation or electricity 

savings that they produce in 2022 and 

future years may be applied toward 

adjusting a CO2 emission rate. For 

example, MWh generation in 2022 from 

a wind turbine installed in 2013 may be 

applied toward adjusting a CO2

emission rate. This 2012 date applies to 

all eligible measures that are used to 

adjust a CO2 emission rate under a state 

plan. For example, eligible measures, 

such as CHP, nuclear power and DSM, 

also must be installed after 2012, but 

only their generation or savings 

produced in 2022 and after can be used 

to adjust a CO2 emission rate. 

As discussed in section VIII.C.2.a, a 

MWh of generation or savings that 

occurs in 2022 or a subsequent year may 

be carried forward (or ‘‘banked’’) and 

applied in a future year. For example, a 

MWh of RE generation that occurs in 

2022 may be applied to adjust a CO2

emission rate in 2023 or future years, 

without limitation.940 These MWh may 

be banked from the interim to final 

periods. 

This eligibility date criterion is 

consistent with the date of installation 

for ‘‘incremental’’ RE capacity that is 

included in the BSER building block 3, 

which is the basis for RE MWh 

incorporated in the CO2 emission 

performance rates for affected EGUs in 

the emission guidelines. For more 

information on RE in the BSER, see 

section V.E. 

Many commenters asserted that 

proposed state goals did not sufficiently 

account for actions states take that 

reduce CO2 emissions prior to the first 

plan performance period, and therefore 

requested that MWhs of electricity 

generation or electricity savings that 

occur prior to the first plan performance 

period be eligible to apply toward 

adjusting the CO2 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 costeffective actions that many sources are 

already doing, while still conforming to 

CO2 performance rates and state goals 

that are forward-looking. In order to 

provide additional incentives for early 

investment in RE and demand-side EE, 

the EPA is also establishing the CEIP, as 

discussed in section VIII.B.2. ERCs 

distributed by states and the EPA 

through this program may also be used 

by affected EGUs to demonstrate 

compliance with an emission standard, 


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941As used here, a measure is ‘‘tied to a state 

plan’’ if it is issued an ERC under approved 

procedures in a rate-based emission standards plan 

or represents quantified and verified MWh energy 

generation or energy savings achieved by an 

approved state measure in a state measures plan. 

942For example, under a rate-based emission 

standard with credit trading, ERCs may be issued 

for qualifying actions that occur both inside and 

outside the state, provided the measures meet 

requirements of EPA-approved state regulations and 

the provider applies to the state for the issuance of 

ERCs. Similarly, under a state measures plan, a state 

might include state requirements such as an RPS, 

where compliance with the RPS can be met through 

out-of-state RE generation. 

and may be banked from the interim to 

final periods. 

Commenters’ concerns about 

treatment of early actions are further 

addressed by changes from proposal to 

the BSER assumptions and the 

methodology used by the EPA to 

establish the CO2 emission performance 

levels and rate-based state CO2 goals in 

the emission guidelines. The specifics of 

these changes are addressed in section 

V.A.3. Three examples of those changes 

are provided below. 

First, affected EGUs that have 

maximized their CO2 emission 

reduction opportunities available 

through early action will be better 

positioned to meet the BSER CO2

emission performance rates or state goal 

applied to affected EGUs in their state. 

For example, a steam generating unit 

that has already reduced its CO2

emission rate through a heat rate 

improvement may have a CO2 emission 

rate of 2,000 lb/MWh whereas its rate 

was 2,100 lb/MWh prior to the 

improvement. Therefore, it has less 

distance to cover to meet its CO2

emission performance rate. 

Second, generation from existing RE 

capacity installed prior to 2013 has been 

excluded from the EPA’s calculation of 

the CO2 emission performances rates in 

the emission guidelines. That RE 

generating capacity will still provide 

zero-emitting generation to the grid 

meeting demand that will not need to be 

addressed by existing affected EGUs and 

will better position states and affected 

EGUs to meet the CO2 performances 

rates or state rate- or mass-based CO2

goals. 

Third, commenters expressed concern 

that demand-side EE targets as part of 

proposed state goals reflected an 

assumption of installation of increased 

EE measures starting in 2017, which 

seemed to be an implicit requirement to 

take action prior to the performance 

period. Because demand-side EE is not 

used in calculating the CO2 emission 

performance rates in the final emission 

guidelines, this is no longer a concern. 

Furthermore, eligible demand-side EE 

actions that occur after 2012 can be 

applied toward adjusting the CO2

emission rates of affected EGUs, 

providing a significant compliance 

option that is not assumed in emission 

performance rates or state goals. 

(b) Demonstration that measures 

substitute for grid generation. 

Eligible measures must be gridconnected. This eligibility criterion 

aligns incremental NGCC generation in 

building block 2. It also aligns with RE 

generation in building block 3 of the 

BSER, which substitutes for the need for 

generation from affected EGUs. 

All EE measures must result in 

electricity savings at a building, facility, 

or other end-use location that is 

connected to the electricity grid. EE 

measures only avoid electric generation 

from grid-connected EGUs if the 

electrical loads where the efficiency 

improvements are made are 

interconnected to the grid. 

Commenters sought clarity on this 

issue, so the EPA is providing this 

requirement as part of the final rule. 

Some commenters advocated for the 

inclusion of measures that were not grid 

connected as eligible resources, arguing 

that some of these measures substituted 

for non-affected EGUs and resulted in 

reductions in CO2 emissions. However, 

eligible measures must be able to 

substitute for generation from affected 

EGUs as defined under this rule, and 

thus must be tied to the electrical grid. 

(c) Geographic eligibility. 

All eligible emission reduction 

measures, including RE generation and 

demand-side EE, may occur in any state, 

with certain limitations, as described 

below. To the extent these measures are 

tied to a state plan,941 these measures 

may be used to adjust a CO2 emission 

rate, regardless of whether the 

associated generation or electricity 

savings occur inside or outside the 

state.942 This approach is generally 

consistent with the approach used in 

building block 3 of the BSER, which 

reflects regionally available RE. It also 

recognizes that emission reduction 

measures have impacts on electricity 

generation across the electricity system, 

both within and beyond a state’s 

borders. A more in-depth discussion of 

the basis for treatment of in-state and 

out-of-state measures is provided in 

section VIII.L. 

State plans must demonstrate that 

emission standards and state measures 

(if applicable) are non-duplicative. 

Given the geographic eligibility 

approach described here, this includes a 

demonstration that a state plan does not 

allow recognition of a MWh, for use in 

adjusting the CO2 emission rate of an 

affected EGU, if the MWh is being or has 

been used for such a purpose under 

another state plan. Discussion of how 

such a demonstration can be made in 

the context of a rate-based emission 

trading program is in section VIII.D.2.b. 

The EPA received many comments on 

the treatment of in-state and out-of-state 

RE and demand-side EE. Most 

commenters recommended crediting of 

both in-state and out-of-state RE and 

demand-side EE measures, similar to the 

final rule approach for eligible emission 

reductions measures. Commenters 

argued that this approach makes sense 

based on the nature of the 

interconnected electricity grid and 

allows states and utilities to fully 

account for their RE and demand-side 

EE efforts, whether that RE or EE, and 

its related impacts, occurs inside or 

outside of their state. Some commenters 

expressed concerns that, at proposal, 

states with significant RE resources had 

large amounts of existing RE capacity 

included in their state CO2 goals, but 

that RE was functionally credited to 

other states for use in meeting their 

goals because it was associated with 

measures (such as an RPS) likely to be 

included in another state’s plan. This 

concern has been addressed through 

changes in the BSER RE assumptions in 

the final rule. This includes 

regionalization of the RE building block, 

and removal of existing RE capacity 

constructed prior to 2012 from the 

building block. The result of these 

changes is that the RE incorporated in 

the BSER is more equally shared across 

states. 

(i) Measures that occur in states with 

mass-based plans. 

As discussed above, eligible measures 

for adjusting the CO2 emission rate of an 

affected EGU may occur in any state, 

with certain conditions. This includes a 

condition that applies to eligible 

measures that occur in a state with an 

EPA-approved plan that is meeting a 

state mass-based CO2 goal. Eligible 

measures that could be used to adjust a 

CO2 emission rate under a rate-based 

state plan which are located in a state 

with a mass-based plan are restricted 

from being counted under another 

state’s rate-based plan. An exception is 

made for RE measures that occur in 

such mass-based states, because of its 

unique role in BSER. RE measures must 

meet additional eligibility criteria in 

order to be used to adjust the CO2

emission rate of an affected EGU in a 

state with a rate-based plan. This 

exception only applies to RE; other 

emission reduction measures that were 

not included in the determination of the 

BSER located in mass-based states, 

including demand-side EE, are 

restricted from ERC issuance in ratebased states. 


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943Where 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. 

944As 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. 

945This 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. 

946Requirements for ERC issuance are addressed 

in section VIII.K.2. 

947This 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. 

These criteria are intended to address 

the fact that eligible measures should 

lead to substitution of generation from 

affected EGUs, with related impacts on 

CO2 emissions from affected EGUs. 

Where states with mass-based plans 

implement mass-based CO2 emission 

standards, CO2 emissions reductions 

from affected EGUs must occur in order 

to comply with these emission 

standards and, unlike the rate-based 

approach, zero- and low-emitting MWhs 

do not play a specified role in 

demonstrating that the mass-based 

standards have been met.943 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 ratebased 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 ratebased state, no incremental CO2

emissions reductions would occur in 

the rate-based state as a result of the 

eligible measures.944 The result would 

be forgone CO2 emission reductions that 

would otherwise occur across the two 

states. These dynamics are further 

addressed in section VIII.L. 

For RE measures located in a massbased 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.945

Some examples of documentation that 

can serve as a demonstration include a 

power delivery contract or power 

purchase agreement. The EPA is giving 

states flexibility regarding the nature of 

this demonstration, but a state plan 

must describe the nature of the required 

demonstration and have it be approved 

by the EPA. 

Under an emission standards plan, 

this demonstration must be made by the 

provider of the RE measure seeking ERC 

issuance under the rate-based emission 

standards in a rate-based state, as part 

of the eligibility application for the 

measure.946 The rate-based state must 

include in its state plan provisions that 

describe a sufficient demonstration of 

geographic eligibility for the RE 

generation under rate-based emission 

standards. 

Further examples of eligible 

demonstrations and how they should be 

outlined in state plans are provided in 

section VIII.L. 

(ii) Measures that occur in states, 

including areas of Indian country, that 

do not have affected EGUs. 

States, including areas of Indian 

country, that do not have any affected 

EGUs within their borders may be 

providers of credits for generation from 

zero- or low-emitting resources to adjust 

CO2 emission rates. In its supplemental 

proposal for the proposed rulemaking, 

the EPA sought comment on whether or 

not jurisdictions without affected fossil 

fuel generation units subject to the 

proposed emission guidelines should be 

authorized to participate in state plans. 

Commenters were supportive of 

allowing those jurisdictions without 

affected EGUs the opportunity to 

participate in state plans. CO2 reduction 

measures in areas without affected 

EGUs have the potential to provide costeffective opportunities to reduce 

emissions and should be available on a 

voluntary basis to affected EGUs. 

Commenters noted that some tribes, for 

example, have many untapped RE 

resources that could be developed, and 

they should be able to realize the 

benefits of contributing to a state plan. 

Commenters stated that because of the 

integrated nature of the U.S. electricity 

grid, it is appropriate to allow all 

jurisdictions with the ability to 

contribute to and benefit from CO2

emission reductions or CO2 emission 

rate adjustments. 

For participating states, they must 

adhere to EM&V standards, installation 

dates, and any other criteria that apply 

to all states. Section VIII.K.3 below 

identifies and discusses the EM&V 

requirements used to quantify MWh 

savings from generation from zero- or 

low-emitting sources. 

States, including areas of Indian 

country, that do not have any affected 

EGUs may provide ERCs to adjust CO2

emissions provided they are connected 

to the contiguous U.S. grid and meet the 

other requirements for eligibility. To 

qualify for ERCs from zero or lowemitting resources, it must be 

demonstrated that the generation was 

delivered to the grid to meet electricity 

load in a state with a rate-based plan.947

Some examples of documentation that 

can serve as a demonstration include a 

power delivery contract or power 

purchase agreement. The EPA is giving 

states flexibility regarding the nature of 

this demonstration, but a state plan 

must describe the nature of the required 

demonstration and have it be approved 

by the EPA. 

In addition to generation from zero- or 

low-emitting resources, demand-side EE 

resources in areas of Indian country 

located within the borders of states with 

rate-based emission standards for 

affected EGUs may also be issued ERCs. 

In these instances, the area of Indian 

country is located within the rate-based 

service area subject to a rate-based state 

plan. The ERCs from demand-side EE 

resources must meet the eligibility 

requirements to adjust a CO2 emission 

rate, including installation date and 

EM&V requirements described below in 

section VIII.K.3. If the area of Indian 

country is located within the borders of 

a state that is meeting a mass-based CO2

goal, then the demand-side EE resources 

are not eligible to be issued ERCs. 

Similarly, demand-side EE resources in 

any state with a mass-based CO2 goal are 

not eligible to provide ERCs. 

Non-contiguous states and territories 

may not be providers of ERCs to the 

contiguous U.S. states. As discussed 

previously in section VII.F, we have not 

set CO2 emission performance goals for 

Alaska, Hawaii, Guam, or Puerto Rico in 

this final rule at this time. 

(iii) Measures that occur outside the 

U.S. 

The EPA will work with states using 

the rate-based approach that are 

interested in allowing the use of RE 

from outside the U.S. to adjust CO2

emission rates. In these cases, all 

conditions for creditable domestic RE 

must be met, including that RE 

resources must be incremental and 

installed after 2012, and all EM&V 

standards must be met. In addition, the 

country generating the ERCs must be 

connected to the U.S. grid, and there 

must be a power purchase agreement or 

other contract for delivery of the power 

with an entity in the U.S. 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, 


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948All state plans must demonstrate that 

measures included in the plan are quantifiable and 

verifiable. See section VIII.K.2 for discussion of 

requirements for the issuance of ERCs, and section 

VIII.K.3 for discussion of EM&V requirements for 

use of RE relied on in a state plan. 

949For 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. 

950As with other RE, only generating capacity 

installed after 2012 would be eligible for use in 

adjusting a CO2 emission rate. 

951As with other RE, only generating capacity 

installed after 2012 would be eligible for use in 

adjusting a CO2 emission rate. 

952 2014 Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990–2012. http://

www.epa.gov/climatechange/ghgemissions/

usinventoryreport.html. 

not eligible for adjusting CO2 emission 

rates under this rule. For example, a 

new transmission interconnection to 

existing RE in Canada would not be 

considered incremental, but a new 

interconnection to RE where the RE was 

built after 2012 would be considered 

incremental. See below in section 

VIII.K.1.a.(3) for more specifics 

regarding the use of incremental 

hydroelectric power in a rate-based 

approach. 

The EPA received comments 

encouraging the use of international 

zero-emitting electricity imports in state 

plans, particularly hydroelectric power 

from Canada. Canada currently provides 

states such as Minnesota and Wisconsin 

with RE through existing grid 

connections. New projects are in various 

stages of development to increase 

generating capacity, which could be 

called upon as a base load resource to 

supplement variable forms of RE 

generation. Commenters said that the 

EPA should permit the use of all 

incremental hydropower—both 

domestic and international—towards 

EGU CO2 emission rate adjustments 

providing that double-counting can be 

prevented; and the EPA acknowledges 

this may be allowable, as long as the 

specified criteria have been met. 

(3) RE. 

RE measures may be used to adjust a 

CO2 emission rate, provided they meet 

the general eligibility requirements 

outlined above and the MWh electricity 

generation is properly quantified and 

verified.948 As used in this section, RE 

includes electric generating 

technologies using RE resources, such as 

wind, solar, geothermal, hydropower, 

biomass and wave and tidal power. A 

capacity uprate at an existing RE facility 

(i.e., an uprate to generating capacity 

originally installed as of 2012 or earlier) 

is eligible to adjust a CO2 emission rate. 

The capacity uprate must occur after 

2012. Such uprates to capacity represent 

incremental capacity added after 2012. 

Quantification and accounting criteria 

for incremental RE (and nuclear 

generation) are as follows. The 

incremental generating capacity (in 

nameplate MW) is divided by the total 

uprated generating capacity (in 

nameplate MW) and then multiplied by 

generation output (in MWh) from the 

uprated generator. For example, if a 

hydroelectric power plant expands 

generating nameplate capacity from 100 

MW to 125 MW and generation output 

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.949

Many commenters supported using 

RE deployment as measures to adjust 

the CO2 emission rate of affected EGUs. 

Some commenters specifically agreed 

with the EPA’s determination that only 

new and incremental RE (including 

hydropower) should be used to adjust 

CO2 emission rates. Those commenters 

objected to counting existing RE that are 

already embedded in the baseline 

emissions and generation mix. A 

significant number of commenters 

supported the integration of RE into a 

rate-based credit trading system. 

Certain additional requirements apply 

for hydropower and biomass (including 

waste-to-energy) RE, as described below. 

(a) Hydroelectric power. 

Consistent with other types of RE, 

new hydroelectric power generating 

capacity installed after 2012 is eligible 

for use in adjusting a CO2 emission rate. 

Relicensed facilities are considered 

existing capacity and, therefore, are not 

eligible for use in adjusting a CO2

emission rate, unless there is a capacity 

uprate as part of the relicensed permit. 

In such a case, only the incremental 

capacity 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-emitting sources would, because of 

their low variable rate, reduce fossil 

emissions. Several commenters 

recommended allowing incremental 

generation from new or uprated zeroemitting sources, including 

hydropower, be available for 

compliance. 

(b) Biomass. 

RE generating capacity installed after 

2012 that uses qualified biomass as a 

fuel source is eligible for use in 

adjusting a CO2 emission rate.950 As 

discussed in section VIII.I.2.c., if a state 

intends to allow for the use of biomass 

as a compliance option for an affected 

EGU to meet a CO2 emission standard, 

a state must propose qualified biomass 

feedstocks and treatment of biogenic 

CO2 emissions in its plan, along with 

supporting analysis and quality control 

measures, and the EPA will review the 

appropriateness and basis for such 

determinations in the course of its 

review of a state plan. Where an RE 

generating unit uses qualified biomass, 

as designated in an approved state plan, 

MWh generation from the unit could be 

used to adjust the reported CO2

emission rate of an affected EGU. Total 

MWh generation from an RE generating 

unit that uses qualified biomass must be 

prorated based on either the heat input 

supplied from qualified biomass as a 

proportion of total heat input or on the 

proportion of biogenic CO2 emissions 

compared to total stack CO2 emissions 

from the RE generating unit. Either 

approach must incorporate the 

approved valuation of biogenic CO2

emissions from qualified biomass in the 

plan (i.e., the proportion of biogenic 

CO2 emissions from use of qualified 

biomass feedstock that would not be 

counted). 

Section VIII.K describes the 

requirements and procedures for EM&V, 

and discusses how all eligible resources 

must demonstrate how they will 

quantify and verify MWh savings using 

best-practice EM&V approaches. One 

way to make this demonstration for 

eligible resources could be to use the 

presumptively approvable EM&V 

approaches that are included in the final 

model trading rule. 

(c) Waste-to-energy. 

Qualified biomass may include the 

biogenic portion of MSW combusted in 

a waste-to-energy facility.951 With 

regard to assessing qualified 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.952 Total MSW 

generation in 2012 was 251 million 

tons, but of that total volume generated, 

almost 87 million tons were recycled 


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953http://www.epa.gov/osw/nonhaz/municipal/

pubs/2012_msw_fs.pdf. 

954http://www.epa.gov/wastes/nonhaz/

municipal/hierarchy.htm. 

955http://www.anr.state.vt.us/dec/wastediv/

WastePrevention/main.htm. 

956http://epa.gov/epawaste/conserve/tools/warm/

Warm_Form.html, https://mswdst.rti.org/. 

957An example is a utility direct load control 

program, such as those where customer air 

conditioning units are cycled during periods of 

peak electricity demand. Actions that shift 

electricity demand from one time of day to another, 

without reducing net electricity use, are not 

eligible, as these measures do not avoid electricity 

use from the grid. Use of emitting generators as a 

DSM measure is also not eligible. 

958Energy 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). 

959This approach focuses on counting the 

qualifying electric generation, which may be an 

input to an energy storage unit. Counting both the 

generation input to energy storage and the output 

from the energy storage unit would be a form of 

double counting. The electric generation that is 

stored may be counted; the subsequent output from 

the storage unit may not. 

and composted.953 Increasing demand 

for electricity generated from waste-toenergy 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.954 For example, Oregon and 

Vermont have strategies that emphasize 

waste prevention, followed by reuse, 

then recycling and composting materials 

prior to treatment and disposal.955

Information in the revised Framework 

for Assessing Biogenic CO2 Emissions 

from Stationary Sources and other 

technical studies and tools (e.g., EPA 

Waste Reduction Model, EPA Decision 

Support Tool) should assist both states 

and the EPA in assessing the role of 

biogenic feedstocks used in waste-toenergy processes, where use of such 

feedstocks is included in a state plan.956

When developing their plans, states 

planning to use waste-to-energy as an 

option for the adjustment of a CO2

emission rate should assess both their 

capacity to strengthen existing or 

implement new waste reduction, reuse, 

recycling and composting programs, and 

measures to minimize any potential 

negative impacts of waste-to-energy 

operations on such programs. States 

must include that information in their 

plan submissions. The EPA will reject 

as qualified biomass any proposed 

waste-to-energy component of state 

plans if states do not include 

information on their efforts to 

strengthen existing or implement new 

waste reduction as well as reuse, 

recycling and composting programs, and 

measures to minimize any potential 

negative impacts of waste-to-energy 

operations on such programs. Only 

electric generation at a waste-to-energy 

facility that is related to the biogenic 

fraction of MSW and that is added after 

2012 is eligible for use in adjusting a 

CO2 emission rate. 

A state plan must include a method 

for determining the proportion of total 

MWh generation from a waste-to-energy 

facility that is eligible for use in 

adjusting a CO2 emission rate. The EPA 

will evaluate the method as part of its 

evaluation of the approvability of the 

state plan. Measuring the proportion of 

biogenic to fossil CO2 emissions can be 

performed through sampling and testing 

of the biogenic fraction of the MSW 

used as fuel at a waste-to-energy facility 

(e.g., via ASTM D–6866–12 testing or 

other methods—ASTM, 2012; Bohar, et 

al. 2010), or based on the proportion of 

biogenic CO2 emissions to total CO2

emissions from the facility. For an 

example of the former method, if the 

biogenic fraction of MSW is 50 percent 

by input weight, only the proportion of 

MWh output attributable to the biogenic 

portion of MSW at the waste-to-energy 

facility may be used to adjust an 

affected EGU CO2 emission rate. 

Alternatively, as an example of the latter 

method, if biogenic CO2 emissions 

represent 50 percent of total reported 

CO2 emissions, a facility would need to 

estimate the fraction of biogenic to fossil 

MSW utilized and the net energy output 

of each component (based on relative 

higher heating values) to determine the 

percent of the MWh output from the 

waste-to-energy facility that may be 

used to adjust an affected EGU’s CO2

emission rate. Section VIII.K describes 

the requirements and procedures for 

EM&V, and discusses how all eligible 

resources must demonstrate how they 

will quantify and verify MWh savings 

using best-practice EM&V approaches. 

One way to make this demonstration for 

eligible resources could be to use the 

presumptively approvable EM&V 

approaches that are included in the final 

model trading rule. 

The EPA received multiple comments 

supporting the use of waste-to-energy as 

part of state plans. Some commenters 

expressed concern that non-biogenic 

materials, such as plastics and metal, 

would be incinerated along with 

biogenic materials. As discussed above, 

only electric generation related to the 

biogenic fraction of MSW at a waste-toenergy facility added after 2012 is 

eligible for use in adjusting a CO2

emission rate. The EPA also received 

comments that expressed concern about 

the potential negative impacts on 

recycling and waste reduction efforts, 

while other commenters asserted that 

waste-to-energy practices encourage 

recycling programs. Some commenters 

also expressed concern about what 

treatment would be approvable for 

emissions from waste-to-energy 

practices. As discussed above, potential 

negative impacts from waste-to-energy 

production on recycling, waste 

reduction, and composting programs 

should be evaluated and efforts to 

mitigate negative impacts must be 

discussed in the supporting 

documentation of state plans. 

(4) DSM. 

Avoided MWh that result from DSM 

may be used to adjust a CO2 emission 

rate. Eligible DSM actions are those that 

are zero-emitting and avoid, rather than 

shift, the use of electricity by an 

electricity end-user.957 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 × hours = MWh avoided). 

DSM measures must be appropriately 

quantified and verified, in accordance 

with requirements in the emission 

guidelines, as discussed in section 

VIII.K.3. 

(5) Energy storage. 

Energy storage may not be directly 

recognized as an 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.958 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.959 However, energy storage can 

be used as an enabling measure that 

facilitates greater use of RE, which can 

be used to adjust a CO2 emission rate. 

For example, utility scale energy storage 

may be used to facilitate greater grid 

penetration of RE generating capacity 

and can also be used to store RE 

generation that may have otherwise 

been shed in times of excess generating 

capacity. Likewise, on-site energy 

storage at an electricity end-user can 


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960For 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. 

961T&D system losses (or ‘‘line losses’’) are 

typically defined as the difference between 

electricity generation to the grid and electricity 

sales. These losses are the fraction of electricity lost 

to resistance along the T&D lines, which varies 

depending on the specific conductors, the current, 

and the length of the lines. The Energy Information 

Administration (EIA) estimates that national 

electricity T&D losses average about 6 percent of the 

electricity that is transmitted and distributed in the 

U.S. each year. 

962 Volt/VAR optimization (VVO) refers to 

coordinated efforts by utilities to manage and 

improve the delivery of power in order to increase 

the efficiency of electricity distribution. VVO is 

accomplished primarily through the 

implementation of smart grid technologies that 

improve the real-time response to the demand for 

power. Technologies for VVO include load tap 

changers and voltage regulators, which can help 

manage voltage levels, as well as capacitor banks 

that achieve reductions in transmission line loss. 

VVO efforts are often closely related to CVR, which 

are actions taken to reduce initial delivered voltage 

levels in feeder transmission lines while remaining 

within the 114 volt to 126 volt range (for normal 

120-volt service) required at the customer meter, 

per the ANSI C84.1 standards. 

963All state plans must demonstrate that 

measures included in the plan are quantifiable and 

verifiable. See section VIII.K.2 for discussion of 

requirements for the issuance of ERCs, and section 

VIII.K.3 for discussion of EM&V requirements for 

use of demand-side EE relied on in a state plan. 

964EE programs may also be implemented by 

other entities. Eligible EE measures that are 

deployed through EE programs are not limited to 

those EE measures deployed through EE programs 

administered by the types of entities listed here. 

enable greater use of RE to meet on-site 

electricity demand.960

The EPA received multiple comments 

regarding the overall merits of energy 

storage. Consistent with the discussion 

above, the majority of commenters 

observed that storage technology 

enables greater grid penetration of RE 

and supports more efficient and 

effective operations of both RE and 

fossil-fuel plants. Commenters further 

noted that energy storage can provide 

RE to the grid when it is most needed, 

while simultaneously taking pressure 

off fossil-fuel plants to respond to 

sudden shifts in demand. Despite broad 

acknowledgment of the benefits of 

storage, public comments underscore its 

indirect and supporting role in 

providing zero-emission MWh to the 

grid (consistent with the EPA’s decision 

to exclude energy storage as an eligible 

measure that can be used to adjust a CO2

emission rate). 

(6) Transmission and distribution 

(T&D) measures. 

Electricity T&D measures that 

improve the efficiency of the T&D 

system and/or reduce electricity use 

may be used to adjust a CO2 emission 

rate. This includes T&D measures that 

reduce losses of electricity during 

delivery from a generator to an end-user 

(sometimes referred to as ‘‘line 

losses’’ 961) and T&D measures that 

reduce electricity use at the end-user, 

such as conservation voltage reduction 

(CVR).962 The EPA received many 

comments in support of advanced 

energy technologies, including energy 

storage and transmission and 

distribution upgrades, and including 

these technologies in the suite of 

potential measures that states could 

consider for emission rate adjustments 

in their state plans. Comments pointed 

out that in addition to helping achieve 

emission standards, T&D efficiency 

improvements make the grid more 

robust and flexible, as well as delivering 

environmental benefits. In many parts of 

the country, grid operators, transmission 

planners, transmission owners and 

regulators are already taking steps to 

expand and modernize T&D networks. 

Commenters suggested that the EPA 

clarify the eligibility and criteria under 

which such measures would be 

permitted in a state plan. 

To be eligible, T&D measures must be 

installed after 2012. This general 

eligibility requirement is discussed 

above in section VIII.K.1.a. The MWh of 

avoided losses or reduction in end-use 

that result from T&D measures must be 

appropriately quantified and verified, as 

discussed in section VIII.K.3. 

(7) Demand-side EE, including water 

system efficiency. 

Demand-side EE measures may be 

used to adjust a CO2 emission rate, 

provided they meet the general 

eligibility requirements outlined above 

and the MWh electricity savings are 

properly quantified and verified.963 As 

used in this section, demand-side EE 

may include a range of eligible 

measures, provided that the measures 

can be quantified and verified in 

accordance with the EM&V 

requirements in the emission 

guidelines, which are addressed in 

section VIII.K.3. Examples of demandside EE measures include, but are not 

limited to, EE measures that reduce 

electricity use in residential and 

commercial buildings, industrial 

facilities, and other grid-connected 

equipment. Water efficiency programs 

that improve EE at water and 

wastewater treatment facilities also 

provide demand-side EE savings 

opportunities. EE measures, for the 

purposes of this section, may consist of 

EE measures installed as the result of 

individual EE projects, such as those 

implemented by energy service 

companies, as well as multiple EE 

measures installed through an EE 

deployment program (e.g. appliance 

replacement and recycling programs, 

and behavioral programs) administered 

by electric utilities, state entities, and 

other private and non-profit entities.964

EE measures, for the purposes of this 

section, may also consist of state or local 

requirements that result in electricity 

savings, such as building energy codes 

and state appliance and equipment 

standards. Other interventions that 

result in electricity savings may also be 

considered an EE measure for the 

purposes of this section, provided the 

intervention can be specified and 

quantified and verified in accordance 

with EM&V requirements in the 

emission guidelines. 

Numerous commenters expressed 

support for including demand-side EE 

as an eligible measure states and 

affected EGUs can use to meet the 

emission guidelines. Commenters 

touted the value of demand-side EE as 

a resource that delivers energy savings, 

lowers bills, creates jobs and reduces 

CO2 emissions. Commenters called for 

the EPA to allow for the use of a broad 

range of demand-side EE measures to 

meet the emission guidelines, including, 

but not limited to, utility and non-utility 

EE deployment programs; energy 

savings performance contracts; 

measures that reduce electricity use in 

residential and commercial buildings, 

industrial facilities and other gridconnected equipment; state and local 

requirements that result in electricity 

savings, such as building energy codes 

and state appliance and equipment 

standards; appliance replacement and 

recycling programs; and behavioral 

programs. The EPA also received 

comments supporting the use of water 

sector EE programs and projects. 

Commenters identified water and 

wastewater utilities as particularly wellsuited for participating in EE programs 

and providing a source of electricity 

savings. Investments such as replacing 

pumps and other aging equipment and 

repairing leaks can result in greater EE. 

The EPA agrees that these electricity 

savings should be eligible for 

adjustments to CO2 emission rates at 

affected EGUs. 

(8) Nuclear power. 

As is discussed in section V.A.3, upon 

consideration of comments received, the 

EPA has not included nuclear 

generation from either existing or under 

construction units in the determination 

of the BSER. In addition to comments 

received on the provisions for 

determining the BSER, the EPA also 

received comments requesting that the 

EPA allow all generation from nuclear 

generating units to be recognized as an 


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965The accounting considerations described in 

this section are for a ‘‘topping cycle’’ CHP unit. A 

topping cycle CHP unit refers to a configuration 

where fuel is first used to generate electricity and 

then heat is recovered from the electric generation 

process to provide additional useful thermal and/ 

or mechanical energy. A CHP unit can also be 

configured as a ‘‘bottoming cycle’’ unit. In a 

bottoming cycle CHP unit, fuel is first used to 

provide thermal energy for an industrial process 

and the waste heat from that process is then used 

to generate electricity. Some waste heat power 

(WHP) units are also bottoming cycle units and the 

accounting treatment for bottoming cycle CHP units 

is provided with the WHP description below. 

eligible measure that can be used to 

adjust a CO2 emission rate. Commenters 

also recommended that the EPA 

consider nuclear generating units and 

RE generating units in a consistent 

manner for CO2 emission rate 

adjustments in state plans. We agree 

with comments that nuclear generation 

and RE should be treated consistently 

when it comes to CO2 emission rate 

adjustments. 

The EPA has determined that 

generation from new nuclear units and 

capacity uprates at existing nuclear 

units will be eligible for use in adjusting 

a CO2 emission rate, just like new and 

uprated capacity RE. However, 

consistent with the reasons discussed 

for not including the preservation of 

existing nuclear 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 zeroemitting generation from new nuclear 

capacity would be expected to replace 

generation from affected EGUs and, 

thereby, reduce CO2 emissions; and the 

continued commitment of the owner/

operators to completion of the new units 

and improving the efficiency of existing 

units through uprates can play a key 

role in state plans. Therefore, consistent 

with treatment of other low- and zeroemitting 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. 

Applicable generation (in MWh) from 

incremental nuclear power is 

determined in the same manner as that 

described for incremental RE above. 

(9) Combined heat and power (CHP) 

units. 

Electric generation from non-affected 

CHP units 965 may be used to adjust the 

CO2 emission rate of an affected EGU, as 

CHP units are low-emitting electric 

generating resources that can replace 

generation from affected EGUs. 

Electrical generation from non-affected 

CHP units that meet the eligibility 

criteria under section VIII.K.1.a can be 

used to adjust the reported CO2

emission rate of an affected EGU. 

Where a state plan provides for the 

use of electrical generation from eligible 

non-affected CHP units to adjust the 

reported CO2 emission rate of an 

affected EGU, the state plan must 

provide a required calculation method 

for determining the MWh that may be 

used to adjust the CO2 emission rate. 

This proposed accounting method must 

adequately address the considerations 

discussed below. The EPA will review 

whether a state’s proposed accounting 

method for electric generation from 

eligible non-affected CHP units is 

approvable per the requirements of the 

final emission guidelines, as part of its 

overall plan review of the rate-based 

emission standards and implementing 

and enforcing measures in the state 

plan. The EPA notes that the proposed 

model rule for a rate-based emission 

trading program includes a proposed 

accounting method for non-affected 

CHP units. The accounting method 

provided in a final model rule could be 

a presumptively approvable accounting 

approach. 

The proposed accounting method in a 

state plan must address the following 

considerations. The accounting 

approach proposed in a state plan must 

take into account the fact that a nonaffected CHP unit is a fossil fuel-fired 

emission source, as well as the fact that 

the incremental CO2 emissions related 

to electrical generation from a nonaffected CHP unit are typically very low. 

In accordance with these 

considerations, a non-affected CHP 

unit’s electrical MWh output that can be 

used to adjust the reported CO2

emission rate of an affected EGU should 

be prorated based on the CO2 emission 

rate of the electrical output associated 

with the CHP unit (a CHP unit’s 

‘‘incremental CO2 emission rate’’) 

compared to a reference CO2 emission 

rate. This ‘‘incremental CO2 emission 

rate’’ related to the electric generation 

from the CHP unit would be relative to 

the applicable CO2 emission rate for 

affected EGUs in the state and would be 

limited to a value between 0 and 1. 

This low CO2 emission rate for 

electrical generation from a non-affected 

CHP unit is a product of both the fact 

that CHP units are typically very 

thermally efficient and the fact that a 

portion of the CO2 emissions from a 

non-affected CHP unit would have 

occurred anyway from an industrial 

boiler used to meet the thermal load in 

the absence of the CHP unit. In contrast, 

the CHP unit also provides the benefit 

of electricity generation while resulting 

in very low incremental CO2 emissions 

beyond what would have been emitted 

by an industrial boiler. As a result, the 

accounting method proposed in a state 

plan should not presume that CO2

emission reductions occur outside the 

electric power sector, but instead only 

would account for the CO2 emissions 

related to the electrical production from 

a CHP unit that is used to substitute for 

electrical generation from affected 

EGUs. 

Non-affected CHP units can use 

qualified biomass fuels. As described in 

section VIII.I.2.c, states must submit 

state plan requirements regarding 

qualified biomass feedstocks and 

treatment of biogenic CO2 emissions in 

state plans, along with supporting 

analysis and quality control measures, 

and the EPA would review the 

appropriateness and basis for such 

determinations in the course of its 

review of the approvability of a state 

plan. Considerations for qualified 

biomass included in state plans are 

discussed in section VIII.I.2.c, while 

accounting requirements for RE using 

biomass are provided in section 

VIII.K.1.a.(3)(b). 

Most comments received on CHP 

recommended that the EPA explicitly 

describe how CHP can be accounted for 

in a state plan. Commenters described 

the CO2 emission reductions achieved 

through CHP’s thermal efficiency and 

the precedent set in other federal and 

state rules that have included CHP as a 

compliance option. Some commenters 

pointed out that without such a 

description, states would not be able to 

readily take advantage of the CO2

emission reductions that result from the 

use of CHP. 

(10) WHP. 

WHP units that meet the eligibility 

criteria under section VIII.K.1 may be 

used to adjust the CO2 emission rate of 

an affected EGU. There are several types 

of WHP units. There are units, also 

referred to as bottoming cycle CHP 

units, where the fuel is first used to 

provide thermal energy for an industrial 

process and the waste heat from that 

process is then used to generate 


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966 In such a configuration, the waste heat stream 

could also be generated from a mechanical process, 

such as at natural gas pipeline compressors. 967This only applies where no additional fossil 

fuel is used to supplement the use of waste heat in 

a WHP facility. Where fossil fuel is used to 

supplement waste heat in a WHP application, MWh 

of electrical generation that can be used to adjust 

the CO2 emission rate of an affected EGU must be 

prorated based on the proportion of fossil fuel heat 

input to total heat input that is used by the WHP 

unit to generate electricity. 968This limitation prevents oversizing the 

thermal output of a WHP unit to exceed the useful 

industrial or other thermal load it is meeting, prior 

to generation of electricity. 

969We note, however, that the final emission 

guidelines allow state measures like emission 

Continued 

electricity.966 There are also WHP 

facilities where the waste heat from the 

initial combustion process is used to 

generate additional power. Under both 

configurations, unless the WHP unit 

supplements waste heat with fossil fuel 

use, there is no additional fossil fuel 

used to generate this additional power. 

As a result, there are no incremental 

CO2 emissions associated with that 

additional power generation. As a 

result, the incremental electric 

generation output from the WHP 

facilities could be considered zeroemitting, for the purposes of meeting the 

emission guidelines, and the MWh of 

electrical output could be used to adjust 

the CO2 emission rate of an affected 

EGU.967 The MWh of electrical output 

from a WHP unit that can be recognized 

may not exceed the MWh of industrial 

or other thermal load that is being met 

by the WHP unit, prior to the generation 

of electricity.968 Most commenters that 

addressed WHP noted the benefits of 

WHP at the same time that they 

discussed the benefits of CHP. The 

commenters reflected that WHP is 

another potential compliance option 

and requested it be discussed explicitly 

as a compliance option that can be used 

to meet the emission guidelines. The 

comments discussed WHP benefits but 

did not elaborate on a preferred 

accounting method for MWh of 

electrical generation from WHP that 

could be used to adjust the CO2

emission rate of an affected EGU. 

b. Measures that may not be used to 

adjust a CO2 emission rate. 

This section addresses measures that 

may not be used to adjust a CO2

emission rate. New, modified, and 

reconstructed EGUs covered under the 

CAA section 111(b) final Standards of 

Performance for Greenhouse Gas 

Emissions from New Stationary Sources: 

Electric Utility Generating Units rule are 

not approvable sources of electric 

generation for adjusting the CO2

emission rate of an affected EGU under 

a rate-based state plan. As discussed 

earlier in section VII.D of this preamble, 

a key concern under this rule is leakage 

to new units that are not covered by the 

emission guidelines. Emissions leakage, 

or increased CO2 emissions due to 

increased utilization of unaffected 

sources, is contradictory to objectives of 

this rule and should, therefore, be 

minimized. Allowing affected EGUs to 

adjust their emission rates as a result of 

lower-emitting new NGCC units not 

covered under this section 111(d) rule 

would not mitigate leakage concerns, 

and could even exacerbate the situation. 

Consequently, new EGUs covered under 

the CAA section 111(b) rule are not 

allowable measures in state plans 

because the EPA believes it would result 

in increased emission leakage. 

The EPA received comments both 

supporting and opposing the use of new 

NGCC units in state plans. In addition 

to leakage concerns, commenters 

expressed concern with the potential 

incentives created by including new 

NGCC capacity in the BSER or as a 

compliance mechanism in state plans. 

Some commenters suggested that 

including new NGCC capacity in the 

BSER or for compliance would distort 

market incentives to build new NGCC 

units, particularly if new units were 

allowed to generate ERCs that could be 

sold to affected EGUs. These 

commenters suggested that the 

additional incentive for new NGCC 

units could make existing NGCC units 

less competitive. Other commenters 

suggested that including new NGCC 

capacity in state plans would promote 

generation from new CO2-emitting units 

at the expense of new zero-emitting 

units, increasing overall emissions 

within a state. This effect would be 

exacerbated if state plans allowed new 

NGCC units to be treated as ‘‘zeroemitting’’ for purposes of compliance— 

as suggested by other commenters. In 

addition, commenters expressed 

concern that the EPA’s inclusion of new 

NGCC capacity in setting the BSER or in 

compliance could negatively impact 

ratepayers over the long-term by 

sending the wrong signal to industry 

and resulting in stranded assets if, in the 

future, carbon emissions become more 

expensive or the EPA proposes to 

incorporate sources built under the 

forthcoming section 111(b) standard 

into the section 111(d) program. 

Commenters also expressed concern 

that including generation from new 

NGCC units could create unreasonable 

uncertainty, given limitations on the 

ability to accurately project new NGCC 

builds, could create undue pressure on 

natural gas prices, and could create 

unfair disparities in the compliance 

opportunities afforded different states. 

In light of the emissions leakage 

concerns, and in consideration of these 

comments, the EPA is not allowing 

shifting generation to new NGCC units 

to be used as a measure for adjusting 

CO2 emission rates for affected EGUs in 

rate-based state plans. 

In addition, other new and existing 

non-affected fossil fuel-fired EGUs that 

are not subject to CAA section 111(b) or 

111(d), such as simple cycle combustion 

turbines, may not be used to adjust the 

CO2 emission rate of an affected EGU. 

While generation from such units could 

substitute for generation from affected 

EGUs, the EPA has determined that 

additional incentives for such 

generation, in the form of an explicit 

adjustment to the CO2 rate of an affected 

EGU, are not necessary or warranted. 

Providing for such an adjustment could 

create perverse incentives for the 

construction of new simple cycle 

combustion turbines that are not subject 

to the applicability criteria of the final 

Standards of Performance for 

Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility 

Generating Units rule. These units could 

provide only limited adjustment credit, 

as operation beyond a certain capacity 

factor threshold would trigger 

applicability under CAA section 111(b). 

Further, providing for the ability to 

generate adjustment credits would 

provide incentives for construction of 

less efficient fossil generating capacity 

than would likely otherwise be 

constructed (e.g., addition of a simple 

cycle combustion turbine rather than a 

NGCC unit). In addition, providing for 

the ability to generate adjustment 

credits could create perverse incentives 

for the continued operation of less 

efficient existing fossil generating 

capacity. Such outcomes run counter to 

the objectives of this final rule. 

c. Measures that reduce CO2

emissions outside the electric power 

sector. 

Measures that reduce CO2 emissions 

outside the electric power sector may 

not be counted toward meeting a CO2

emission performance level for affected 

EGUs or a state CO2 goal, under either 

a rate-based or mass-based approach, 

because all of the emission reduction 

measures included in the EPA’s 

determination of the BSER reduce CO2

emissions from affected EGUs. 

Examples of measures that may not be 

counted toward meeting a CO2 emission 

performance level for affected EGUs or 

a state CO2 goal include GHG offset 

projects representing emission 

reductions that occur in the forestry and 

agriculture sectors,969 direct air capture, 


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64904 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

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. 

970 79 FR 34830, 34913. 

971These requirements are described in detail in 

section VIII.D.2. 

972As 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. 

973By ‘‘integrity of a rate-based emission trading 

program’’, the EPA is referring to elements in the 

design and administration of a program necessary 

to assure that emission standards implemented 

using a rate-based emission trading approach are 

quantifiable, verifiable, enforceable, nonduplicative, and permanent. 

974See section VIII.K.1 for a discussion of the 

accounting method used to adjust a CO2 emission 

rate. 

975As used in this section, the term ‘‘EE program’’ 

refers to an EE deployment program. An EE 

program involves deployment of multiple EE 

measures or EE projects, such as utility- or stateadministered EE incentive programs that accelerate 

the deployment of EE technologies and practices. 

As used in this section, the term ‘‘EE/RE project’’ 

refers to a discrete EE project (e.g., an EE upgrade 

to a commercial building or set of buildings) or a 

RE generator (e.g., a single wind turbine or group 

of turbines). 

and crediting of CO2 emission 

reductions that occur in the 

transportation sector as a result of 

vehicle electrification. 

2. Requirements for Rate-Based 

Emission Trading Approaches 

As made clear in the proposal,970 all 

emission standards in a state plan must 

be quantifiable, verifiable, enforceable, 

non-duplicative and permanent.971 This 

requirement is applicable to emission 

standards that include a rate-based 

emission trading program. The State 

Plan Considerations TSD for the 

proposal also explained that in order to 

ensure a plan is enforceable, a state plan 

must: identify in its plan the entity or 

entities responsible for meeting 

compliance and other enforceable 

obligations under the plan; include 

mechanisms for demonstrating 

compliance with plan requirements or 

demonstrating that other binding 

obligations are met; and provide a 

mechanism(s) for legal action if affected 

EGUs are not in compliance with plan 

requirements or if other entities fail to 

meet enforceable plan obligations. A 

state plan using a rate-based emission 

trading approach must therefore include 

rate-based emission standards for 

affected EGUs along with related 

implementation and compliance 

requirements and mechanisms.972 These 

related requirements include those 

applicable to rate-based emission 

standards more broadly: CO2 emission 

monitoring, reporting, and 

recordkeeping requirements for affected 

EGUs, including requirements for 

monitoring and reporting of useful 

energy output. By satisfactorily 

addressing these requirements, state 

plans including a rate-based emission 

trading program will be able to meet the 

statutory requirements of CAA section 

111(d) regarding the need for state plans 

to provide for the implementation and 

enforcement of emission standards, as 

well as meet the requirement that each 

emission standard be quantifiable, 

verifiable, non-duplicative, permanent, 

and enforceable with respect to each 

affected EGU. 

The EPA also specifically proposed 

that for state plans that rely on measures 

that avoid EGU CO2 emissions, such as 

RE and demand-side EE measures, the 

state will also need to include 

quantification, monitoring, and 

verification provisions in its plan for 

these measures. The EPA is finalizing 

requirements specific to rate-based 

emission trading programs as 

requirements the EPA has determined 

are necessary to assure the integrity of 

a rate-based approach that includes an 

emission trading program, and therefore 

assures a state plan using such an 

approach appropriately provides for the 

implementation and enforcement of 

rate-based emission standards in 

accordance with CAA section 111(d).973

These specific requirements for a ratebased emission trading program include 

provisions for issuance of ERCs by the 

state and/or its designated agent; 

provisions for tracking ERCs, from 

issuance through submission for 

compliance; and the administrative 

process for submission of ERCs by the 

owner or operator of an affected EGU to 

the state, in order to adjust its reported 

CO2 emission rate when demonstrating 

compliance with a rate-based emission 

standard.974 These requirements must 

be submitted for inclusion in the 

federally enforceable plan, per the 

statutory requirement that states provide 

for the implementation and enforcement 

of emission standards. A rate-based 

trading program would provide for the 

implementation and enforcement of 

rate-based emission standards for a state 

plan that allows its affected EGUs to 

adjust a rate by the use of an ERC. 

The EPA will review a state plan 

submittal including a rate-based 

emission trading program to assure that 

the plan contains the requirements 

necessary to assure the integrity of a 

rate-based approach, and therefore 

provide for the implementation and 

enforcement of rate-based emission 

standards. These requirements are 

discussed in more detail in this section. 

The EPA also notes it is proposing 

model rules for both mass-based and 

rate-based emission trading programs. 

State plans that include the finalized 

model rule for a rate-based emission 

trading program could be presumptively 

approvable as meeting the requirements 

of CAA section 111(d) and these 

emission guidelines. The EPA would 

evaluate the approvability of such plans 

through independent notice and 

comment rulemaking. 

A state may issue ERCs to an affected 

EGU that performs at 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 demandside EE measures, as well as other types 

of measures, as discussed in section 

VIII.K.1.a.975

ERCs may be used by an affected EGU 

to adjust its reported CO2 emission rate 

when demonstrating compliance with a 

rate-based emission standard. This 

adjustment is made by adding MWh to 

the denominator of an affected EGU’s 

reported CO2 emission rate, in the 

amount of submitted ERCs, resulting in 

a lower adjusted rate. To demonstrate 

compliance with a rate-based emission 

standard, an affected EGU would report 

its CO2 lb/MWh emission rate to the 

state regulatory body, and would also 

surrender to the state any ERCs it 

wishes to use to adjust its reported 

emission rate. The state regulator would 

then cancel the submitted ERCs. The 

affected EGU would add the MWh the 

ERCs represent to the denominator of its 

reported CO2 lb/MWh emission rate to 

demonstrate compliance with its 

emission standard. The state regulator 

could facilitate its evaluation of the 

affected EGU’s compliance (as well as 

evaluation by the affected EGU, the 

EPA, and others) by providing 

functionality in its tracking system to 

run such compliance calculations. If the 

affected EGU’s adjusted CO2 emission 

rate is equal to or lower than its 

applicable emission rate standard, the 

affected EGU would be in compliance. 

a. Issuance of ERCs to affected EGUs. 

ERCs may be issued to affected EGUs 

that emit below a specified CO2

emission rate, as discussed below. For 

issuance of ERCs to affected EGUs, the 

state plan must specify the accounting 

method and administrative process for 

ERC issuance. This includes the 


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976For all calculations in this section, where the 

result is a negative value, no ERCs would be issued. 

977This term represents the reported MWh by the 

affected EGU on an annual basis. 

978This term represents the ‘‘reference rate.’’ 

979This term represents the annual reported CO2

emission rate of the affected EGU. 

980For all calculations in this section, where the 

result is a negative value, no ERCs would be issued. 

981The ‘‘reference rate.’’ 

982The ‘‘reference rate.’’ 

983This is the CO2 emission performance rate for 

affected stationary combustion turbines in the 

emission guidelines. 

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.K.2.c. 

The accounting method that may be 

applied in a state plan differs depending 

on whether a state plan includes a 

single rate-based emission standard that 

applies to all affected EGUs (e.g., if a 

plan is designed to meet a state ratebased 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 ratebased emission standard that applies to 

all affected EGUs, the reference rate is 

the CO2 emission rate limit for affected 

EGUs. In this instance, ERCs may be 

issued based on an affected EGU’s 

reported CO2 emission rate as a 

proportion of the emission limit rate. 

For example, if the emission rate limit 

is 2,000 lb CO2/MWh and the affected 

EGU emits at a rate of 1,000 lb CO2/

MWh, 0.5 MWh would be awarded for 

every MWh generated by the affected 

EGU. ERCs would be issued to affected 

EGUs in whole MWh increments. The 

calculation method is as follows: 

ERCs 976 = reported MWh by affected 

EGU 977 × ((CO2 emission rate limit for 

affected EGUs 978—affected EGU 

reported CO2 emission rate 979)/CO2

emission rate limit for affected EGUs) 

For the example above, the 

calculation is as follows: 

ERCs = MWh reported × (2,000¥1,000)/

2,000 = MWh reported × 0.5 

If the affected EGU in this example 

generated 1,000,000 MWh, 500,000 

ERCs would be issued. 

Where a state plan includes separate 

emission standards for subcategories of 

affected EGUs, specifically affected 

fossil fuel-fired electric utility steam 

generating units and stationary 

combustion turbines, the reference rate 

differs for affected fossil fuel-fired 

electric utility steam generating units 

and stationary combustion turbines. 

Additionally, if the state plan applies 

emission standards for its affected EGUs 

that are equal to the subcategorized CO2

emission performance rates there is a 

unique opportunity for the adjustment 

of an affected EGU’s emission rate using 

ERCs that are generated as a result of 

building block 2 incremental NGCC unit 

operation. The EPA is requiring state 

plans to account for incremental NGCC 

generation in ERC generation if a state 

plan applies the subcategorized CO2

emission performance rates to its 

affected EGUs as emission standards. 

Additionally, the EPA is requiring that 

a NGCC unit is not able to use ERCs 

generated by it or any other NGCC unit’s 

building block 2 incremental generation. 

For affected steam generating units, 

the reference CO2 emission rate is the 

assigned CO2 emission rate limit for 

steam generating units, and the 

following accounting method for 

generating ERCs applies: 

ERCs 980 = reported MWh × ((steam 

generating unit CO2 emission rate 

limit 981—steam generating unit 

reported CO2 emission rate)/steam 

generating unit CO2 emission rate limit). 

For an affected NGCC stationary 

combustion turbine in a subcategorized 

rate-based emission trading program, 

the following equation provides a 

required accounting method for 

generating ERCs based on operation 

with respect to the NGCC unit’s 

emission standard: 

ERCs = NGCC unit’s reported MWh— 

((NGCC unit’s CO2 emission 

standard 982—NGCC unit’s reported CO2

emission rate)/NGCC unit’s CO2

emission standard) 

According to this equation, ERC 

issuance is assessed based on the 

difference between the CO2 emission 

rate standard for the NGCC unit 983 and 

the reported CO2 emission rate of the 

affected NGCC unit. In other words, 

affected NGCC stationary combustion 

turbines earn ERCs for generation when 

they perform at an emission rate better 

than the reference rate for stationary 

combustion turbines, similarly to how 

affected steam units can earn ERCs. 

In a subcategorized rate-based 

emission trading program, a state must 

use the incremental operation of an 

affected NGCC unit quantified for 

building block 2 to allow a NGCC unit 

to generate ERCs based on its expected 

incremental generation. 

A state plan that provides for the use 

of ERCs issued based on incremental 

affected NGCC generation must provide 

a required calculation method that 

allows for issuance of ERCs based on the 

ability of incremental generation from 

affected stationary combustion turbines 

to substitute for generation from affected 

steam generating units (as represented 

in building block 2), while also 

respecting the fact that affected 

stationary combustion turbines must 

also meet an assigned CO2 emission rate 

limit for the entirety of its MWh energy 

output. This accounting method must 

reflect the application of the BSER, as 

described in section V, and the 

accounting method must not create 

incentives to rearrange dispatch 

between existing NGCC units to 

generate additional ERCs without 

changing the overall level of NGCC 

generation. 

The EPA will review whether a state’s 

accounting method is approvable per 

the requirements of the statute and this 

final rule as part of its overall plan 

review of the rate-based emission 

standards and implementing and 

enforcing measures in the state plan. 

The EPA notes that the proposed model 

rule for a rate-based emission trading 

program includes a proposed 

accounting method and takes comments 

on alternatives. The accounting method 

provided in a final model rule could be 

a presumptively approvable approach 

for issuance of ERCs based on the ability 

of incremental generation from affected 

stationary combustion turbines to 


tkelley on DSK3SPTVN1PROD with BOOK 2
64906 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

984Qualifying measures that can be used to adjust 

the CO2 emission rate of an affected EGU are 

discussed at section VIII.K.1, and include 

incremental NGCC, RE, demand-side EE, and other 

measures, such as DSM, CHP and incremental 

nuclear generation. 

985For 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 section 

VIII.K.1. 

986As 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. 

987The entity implementing the EE/RE program 

or project (referred to in the preamble as a 

‘‘provider’’) would submit the application. This is 

the identified entity to which ERCs would 

ultimately be issued, to a tracking system account 

held by the entity. Such entities could include a 

wide variety of parties that implement EE/RE 

programs and projects, including owners or 

operators of affected EGUs, electric distribution 

companies, independent power producers, energy 

service companies, administrators of state EE 

programs, and administrators of industrial EE 

programs, among others. 

988The verification process includes confirmation 

that quantified MWh are non-duplicative and 

permanent (i.e., are not being used in any other 

state plan to demonstrate compliance with an 

emission standard or achievement of an emission 

performance rate or state CO2 emission goal). 

989 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/verification.htm. 

990This includes ensuring that multiple parties 

do not submit an eligibility application for the same 

EE program or project, or for the same RE generator. 

991Emission standards must be ‘‘non-duplicative’’ 

as described in section VIII.D.2. 

substitute for generation from affected 

steam generating units. A state’s 

accounting requirements for generation 

of ERCs based on incremental affected 

NGCC generation must maintain 

consistency with the EPA’s application 

of the BSER when calculating CO2

emission performance rates for affected 

stationary combustion turbine and 

steam generating units. In particular, a 

state’s accounting method must 

maintain consistency of accounting in a 

state rate-based CO2 emission standard 

with the EPA’s application of building 

block 2 in calculating CO2 emission 

performance rates for affected fossil 

fuel-fired electric utility steam 

generating units and stationary 

combustion turbines, which is based on 

use of incremental generation from 

affected stationary combustion turbine 

to replace generation from affected 

steam generating units. 

b. Issuance of ERCs for RE, demandside EE, and other measures. 

ERCs may be issued for qualifying 

measures.984 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 

project 985 to the administering state 

regulator (or its agent 986). The state 

regulator reviews the application to 

determine whether, in this example, an 

EE/RE program or project meets 

eligibility requirements for the issuance 

of ERCs.987 An eligibility application 

must include a description of the 

program or project, a projection of the 

MWh generation or energy savings 

anticipated over the life of the program 

or project, and an EM&V plan that meets 

state plan requirements. The EM&V plan 

must describe how MWh of RE 

generation or energy savings resulting 

from the program or project will be 

quantified and verified.988 A state, in its 

emission standard regulations, must 

include requirements for EM&V plans 

that are consistent with the 

requirements in the emission guidelines 

for EE/RE measures and other eligible 

measures, as discussed in sections 

VIII.K.1 and VIII.K.3. 

The EPA has determined that state 

requirements for an eligibility 

application must include review of the 

application by an independent verifier, 

approved by the state as eligible per the 

requirements of the final emission 

guidelines to provide such verification, 

prior to submittal. This requirement 

builds on the approach used for 

assessing GHG offset projects, both in 

international emission trading programs 

and the GHG emission budget trading 

programs implemented by California 

and the RGGI participating states.989 An 

assessment by an independent verifier 

would be included as a component of an 

eligibility application. 

The EPA has determined that 

independent verification requirements 

are necessary to ensure the integrity of 

state rate-based emission trading 

programs included in a state plan, given 

the wide range of eligible measures that 

may generate ERCs and the broad 

geographic locations in which those 

measures may occur. Inclusion of an 

independent verification component 

provides technical support for state 

regulatory bodies to ensure that 

eligibility applications and M&V reports 

are thoroughly reviewed prior to 

issuance of ERCs. Inclusion of an 

independent verification component is 

also consistent with similar approaches 

required by state PUCs for the review of 

demand-side EE program results and 

GHG offset provisions included in state 

GHG emission budget trading programs. 

State plans with rate-based emission 

trading programs must include 

requirements regarding the qualification 

status of an independent verifier. An 

independent verifier is a person 

(including any company, any corporate 

parent or subsidiary, any contractors or 

subcontractors, and the actual person) 

who has the appropriate technical and 

other qualifications to provide 

verification reports. The independent 

verifier must not have, or have had, any 

direct or indirect financial or other 

interest in the subject of its verification 

report or ERCs that could impact its 

impartiality in performing verification 

services. State plans must require that a 

person be approved by the state as an 

independent verifier, as defined by this 

final rule, as eligible to perform the 

verifications required under the 

approved state plan. State plans must 

also include a mechanism to 

temporarily or permanently revoke the 

qualification status of an independent 

verifier, such that it can no longer 

provide verification services related to 

an eligibility application or M&V report 

for at least the duration of the period it 

does not meet the qualification 

requirements for independent verifiers 

in an approved state plan. The EPA’s 

proposed model rate-based emission 

trading rule contains provisions 

addressing accreditation and conflicts of 

interest for independent verifiers. State 

plans that adopt the finalized model 

rule could be presumptively approvable 

with respect to these requirements 

regarding independent verifiers. 

The state’s eligibility requirements 

and application procedures must ensure 

that only eligible actions may generate 

ERCs and that documentation is 

submitted only once for each program or 

project, and to only one state 

program.990 These provisions will 

ensure that actions that are eligible for 

the issuance of ERCs are ‘‘nonduplicative.’’ 991 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 M&V report to the state regulatory 

body documenting the results of the 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64907 

992State rate-based emission trading program 

regulations must specify the frequency for 

submission of M&V reports for approved qualified 

measures that have been deemed eligible to 

generate ERCs. These reporting periods should be 

annual, but a state could consider shorter or longer 

periods, depending on the type of ERC resource. 993EE/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. 994This must include electronic Internet access to 

such information in the tracking system. 

995 ‘‘Compliance true-up’’ refers to ERC 

submission by an owner or operator of an affected 

EGU to adjust a reported CO2 emission rate, and 

determination of whether the adjusted rate is equal 

to or lower than the applicable rate-based emission 

standard. 

996States also have the option to participate in 

the CEIP, under which they can issue ERCs for 

MWh generation or savings that occur in 2020–2021 

for measures implemented following submission of 

a final state plan, and receive matching ERCs from 

a federal pool. See section VIII.B.2 for a detailed 

discussion. The ERCs issued under this program 

can also be banked during and between the interim 

and final compliance period. 

997Banking under mass-based emission budget 

trading programs, and the rationale for banking 

provisions, is addressed below in section VIII.J.2.c. 

998The 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. 

program or project in MWh of electric 

generation or energy savings.992 These 

results are quantified according to the 

EM&V plan that was approved as part of 

step one. These results are verified by 

an accredited independent verifier, and 

its verification assessment must be 

included as part of the M&V report 

submitted to the state regulatory body. 

The administering state regulator (or its 

agent) then reviews the M&V report, and 

determines the number of ERCs (if any) 

that should be issued, based on the 

report. Finally, the state regulatory body 

(or its agent) issues ERCs to the provider 

of the approved program or project. 

These ERCs are issued to the tracking 

system account held by the program or 

project provider. 

State plan requirements must ensure 

that only one ERC is issued for each 

verified MWh. This is addressed 

through registration in the tracking 

system of programs and projects 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.993

The tracking system must provide 

transparent electronic public access to 

submitted M&V reports and regulatory 

approvals related to such reports.994

Such reports are the basis for issuance 

of ERCs. 

c. Tracking system requirements. 

State requirements must include 

provisions to ensure that ERCs issued to 

any eligible entity are properly tracked 

from issuance to submission by affected 

EGUs for compliance (where ERCs are 

‘‘surrendered’’ by the owner or operator 

of an affected EGU and ‘‘retired’’ or 

‘‘cancelled’’), 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,995 and an accompanying tracking 

system that meets requirements 

specified in the emission trading 

program regulations. Each issued ERC 

must have a unique identifier (e.g., 

serial number) and the tracking system 

must provide for traceability of issued 

ERCs back to the program or project for 

which they were issued. 

The EPA received a number of 

comments from states and stakeholders 

about the value of the EPA’s support in 

developing and/or administering 

tracking systems to support state 

administration of rate-based emission 

trading systems. This could include 

regional systems and/or a national 

system. The EPA is exploring options 

for providing such support and is 

conducting an initial scoping 

assessment of tracking system support 

needs and functionality. 

d. Effect of improperly issued ERCs. 

Because the goal of this rulemaking is 

the actual reduction of CO2 emissions, 

it is fundamental that ERCs represent 

the MWh of energy generation or 

savings they purport to represent. To 

this end, only valid ERCs that actually 

meet the standards articulated in this 

rule may be used to satisfy any aspect 

of compliance by an affected EGU with 

emission standards. Despite safeguards 

included in the structure of ERC 

issuance and tracking systems, such as 

the review of eligibility applications and 

M&V reports, and state issuance of 

ERCs, ERCs may be issued that do not, 

in fact, represent eligible zero-emission 

MWh as required in the emission 

guidelines. A variety of situations may 

result in such improper ERC issuance, 

ranging from simple paperwork errors to 

outright fraud. 

An approvable state plan that allows 

affected EGUs to comply with their 

emission standards in part through 

reliance on ERCs must include 

provisions making clear that an affected 

EGU may only demonstrate compliance 

with an ERC that represents the one 

MWh of actual energy generation or 

savings that it purports to represent and 

otherwise meets the emission 

guidelines. 

e. Banking of ERCs. 

ERCs issued in 2022 or a subsequent 

year may be carried forward (or 

‘‘banked’’) and used for demonstrating 

compliance in a future year.996 For 

example, an ERC issued for a MWh of 

RE generation that occurs in 2022 may 

be applied to adjust a CO2 emission rate 

in 2023 or future years without 

limitation. ERCs may be banked from 

the interim plan performance period to 

the final plan performance period. 

Banking provides a number of 

advantages while ensuring that the same 

output-weighted average CO2 emission 

rates of the interim and final state CO2

goals are achieved over the course of a 

state plan. Banking provisions have 

been used extensively in rate-based 

environmental programs and massbased emission budget trading 

programs.997 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.998 State plans must specify 

whether the state is allowing or 

restricting the banking of ERCs between 

compliance periods for affected EGUs. 

State plans must also prohibit 

borrowing of any ERCs from future 

compliance periods by affected EGUs or 

eligible resources. 

f. Considerations for ERC issuance. 

The EPA notes that state-administered 

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 rate-based emission trading system 

in the form of ERCs. These programs 

have been the primary means for 

delivering EE programs and energy 

savings at scale, and also allow for a 

state to conduct a portfolio planning 

process to guide EE program design and 

focus in a manner that best provides 

multiple benefits to electricity 

ratepayers in a state. Such portfolio 

planning processes typically treat EE as 

an energy resource comparable to 

electricity generation. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64908 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

999EM&V is defined to mean the set of 

procedures, methods, and analytic approaches used 

to quantify the MWh from demand-side EE and RE 

and other measures, and thereby ensure that the 

resulting savings and generation are quantifiable 

and verifiable. 

1000The EPA recognizes that EM&V best practices 

are routinely evolving to reflect changes in markets, 

technologies and data availability. Therefore the 

agency is providing draft EM&V guidance with the 

proposed model rule, which can be updated over 

time to address any such changes to best practices. 

The guidance can also identify and describe 

alternative quantification approaches that may be 

approved for use, provided that such approaches 

meet the requirements of the finalized EM&V 

requirements. 

1001 In the context of demand-side EE, ‘‘measure’’ 

refers to an installed piece of equipment or system 

at an end-use energy consumer facility, a strategy 

intended to affect consumer energy use behaviors, 

or a modification of equipment, systems or 

operations that reduces the amount of electricity 

that would have delivered an equivalent or 

improved level of end-use service in the absence of 

EE. 

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 state RPS 

and EERS requirements) or for use in 

voluntary markets. An ERC may be 

issued based on the same data and 

verification requirements used by 

existing REC and EEC tracking systems 

for issuance of RECs and EECs. 

The EPA notes that the definitions of 

other instruments, such as RECs, differ 

(as established under state statute, 

regulations, and PUC orders) and that 

requirements under state regulatory 

programs that use such instruments, 

such as state RPS, also differ. As a 

result, states may want to assess, when 

developing their state plan, how such 

existing instruments may interact with 

ERCs. For example, a state may want to 

assess how issuance of ERCs pursuant to 

a state plan may interact with 

compliance with a state RPS by entities 

affected under relevant state RPS 

regulations or PUC orders. The 

interaction of other instruments and 

ERCs may also impact existing or future 

arrangements in the private 

marketplace. Actions taken by states, 

separate from the design of their state 

plan, could address a number of these 

potential interactions. For example, 

state RPS regulations that specify a REC 

for a MWh of RE generation, and the 

attributes related to that MWh, may or 

may not explicitly or implicitly 

recognize that the holder of the REC is 

also entitled to the issuance of an ERC 

for a MWh of electricity generation from 

the eligible RE resource. This could 

impact existing and future RE power 

purchase agreements or REC purchase 

agreements. Such interactions among 

existing instruments and ERCs could 

also impact how marketing claims are 

made in the voluntary RE market. How 

a state might choose to address these 

potential interactions will depend on a 

number of factors, including the utility 

regulatory structure in the state, existing 

statutory and regulatory requirements 

for state RPS, and existing RE power 

purchase agreements and REC contracts. 

g. Program review. 

The EPA is requiring that states 

periodically review the administration 

of their rate-based emission trading 

programs. The results of these program 

reviews must be submitted by states to 

the EPA as part of their required reports 

on the implementation of their state 

plans, as described in sections 

VIII.D.a.(5) and VIII.D.2.b.(4), and must 

be made publicly available. Such a 

review submitted as part of a required 

state report provides for the 

implementation of rate-based emission 

standards per the requirements of CAA 

section 111(d)(2). For a rate-based 

emission trading program, the review 

must cover the reporting period 

addressed in the state’s periodic reports 

to the EPA on plan implementation. 

The program review must address all 

aspects of the administration of a state’s 

rate-based emission trading program, 

including the state’s evaluations and 

regulatory decisions regarding eligibility 

applications for ERC resources and M&V 

reports (and associated EM&V 

activities), and the state’s issuance of 

ERCs. The program review must assess 

whether the program is being 

administered properly in accordance 

with the state’s approved plan; whether 

ERC eligibility applications and M&V 

reports are being properly evaluated and 

acted upon (i.e., approved or 

disapproved); whether reported annual 

MWh of generation and savings from 

qualified ERC resources are being 

properly quantified, verified, and 

reported in accordance with approved 

EM&V plans, and whether appropriate 

records are being maintained. The 

program review must also address 

determination of the eligibility of 

verifiers by the state and the conduct of 

verifiers, including the quality of 

verifier reviews. Where significant 

deficiencies are identified by the state’s 

program review, those deficiencies must 

be rectified by the state in a timely 

manner. 

States must collect, compile, and 

maintain sufficient data in an 

appropriate format to support the 

periodic program review. The EPA will 

review the results of each program 

review. The EPA may also audit a state’s 

administration of its rate-based emission 

trading program and pursue appropriate 

remedies where significant deficiencies 

are identified. 

3. EM&V Requirements for RE, DemandSide EE, and Other Measures Used To 

Adjust a CO2 Rate 

This section discusses EM&V for RE, 

demand-side EE, and other measures 

that are used to generate ERCs or 

otherwise adjust an emission rate.999

EM&V is applied for purposes of 

quantifying and verifying MWh in ratebased state plans, as described below. 

Rate-based state plans must require that 

eligible resources document in EM&V 

plans and M&V reports how all MWh 

saved and generated from eligible 

measures will be quantified and 

verified. Additionally, with respect to 

EM&V, the EPA’s proposed model rule 

identifies certain industry best practices 

that, upon finalization, could be 

adopted as presumptively approvable 

components of a state plan.1000

As discussed in section VIII.K.1, 

quantified and verified MWh of RE 

generation, EE savings,1001 and other 

eligible measures may be used to adjust 

a CO2 emission rate when 

demonstrating compliance with the 

emission guidelines. In states 

implementing emission standard type 

plans with rate-based trading, affected 

EGUs adjust their reported emission rate 

using ERCs, which represent MWh that 

are quantified and verified according to 

the EM&V requirements described in 

this section. The EPA will evaluate the 

overall approvability of the state plan 

taking into consideration whether the 

state’s submitted EM&V requirements 

satisfy these final emission guidelines. 

a. Discussion of proposed EM&V 

approach and public comment. 

The EPA proposed that a state plan 

that incorporates RE and demand-side 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64909 

1002See discussion beginning on p. 34 of the State 

Plan Considerations TSD for the Clean Power Plan 

Proposed Rule: http://www2.epa.gov/carbonpollution-standards/clean-power-plan-proposedrule-state-plan-considerations. 

EE measures must include an EM&V 

plan that explains how the effect of 

these measures will be determined in 

the course of plan implementation. The 

proposal sought comment on the 

suitability of current state and utility 

EM&V approaches for RE and demandside EE programs in the context of an 

approvable state plan, and on whether 

harmonization of state approaches, or 

supplemental actions and procedures, 

should be required in an approvable 

state plan, provided that supporting 

EM&V documentation meets applicable 

minimum requirements. In the proposal, 

the EPA also indicated that it would 

issue guidance to help states, sources, 

and project providers quantify and 

verify MWh savings and generation 

resulting from zero-emitting RE and 

demand-side EE efforts. 

The proposal and associated ‘‘State 

Plans Considerations’’ TSD 1002

suggested that the EPA’s EM&V 

requirements could leverage existing 

industry practices, protocols, and 

tracking mechanisms currently utilized 

by the majority of states implementing 

RE and demand-side EE. The EPA 

further noted that many state regulatory 

bodies and other entities already have 

significant EM&V infrastructure in place 

and have been applying, refining, and 

enhancing their evaluation and quality 

assurance approaches for over 30 years, 

particularly with regard to the 

quantification and verification of energy 

savings resulting from utilityadministered EE programs. The 

proposal also observed that the majority 

of RE generation is typically quantified 

and verified using readily available, 

reliable, and transparent methods such 

as direct metering of MWh. 

As a result, the agency took comment 

on whether this infrastructure is 

appropriate in the context of approvable 

state plans for use in rate-based state 

plans that include RE, demand-side EE, 

and other measures. The majority of 

commenters addressing this question 

responded affirmatively, indicating that 

existing EM&V infrastructure is 

appropriate to assure quality, 

credibility, and integrity. However, 

commenters also noted that EM&V 

methods are routinely improving and 

changing over time, and that the EPA’s 

requirements and guidance should be 

responsive to such changes, should 

avoid locking in outdated methods, and 

should be updated to maintain 

relevance. 

Another point made by commenters is 

that, despite the observed improvements 

in EM&V over time, quantification 

knowledge is more robust for some EE 

program and policy types than for 

others. Additionally, there is relatively 

limited experience applying EM&V 

protocols and procedures to emission 

trading programs, where each MWh of 

replaced generation can be bought and 

sold by a regulated source. As a result, 

the EPA’s final emission guidelines and 

proposed model rule include a number 

of safeguards and quality-control 

features that are intended to ensure the 

accuracy and reliability of quantified EE 

savings. 

b. Requirements for EM&V and M&V 

submittals. 

As discussed in section VIII.K.2, these 

final guidelines require that state plans 

include a requirement that EM&V plans 

and M&V reports be submitted to the 

state for rate-based emission trading 

programs. States must require that at the 

initiation of an eligible measure, project 

providers must develop and submit to 

the state an EM&V plan that documents 

how requirements for quantification and 

verification will be carried out over the 

period that MWh generation or savings 

are produced. States must also require 

that after a project or program is 

implemented, the provider must submit 

periodic M&V reports to confirm and 

describe how each of the requirements 

was applied. These reports must also 

specify the actual MWh savings or 

generation results, as quantified by 

applying EM&V methods on a 

retrospective (ex-post) basis. States may 

not allow MWh values that are 

quantified using ex-ante (preimplementation) estimates of savings. 

As previously described, the EPA took 

comment on the suitability of current 

state and utility EM&V approaches for 

RE and demand-side EE programs in the 

context of an approvable state plan. 

These final requirements regarding 

EM&V plans and M&V reports are 

intended to leverage and closely 

resemble those already in routine use. 

For energy generating resources, 

including RE resources, states may 

leverage the programs and infrastructure 

they have in place for achievement of 

their RPS and take advantage of 

registries in place for the issuance and 

tracking of RECs. Many existing REC 

tracking systems already include wellestablished safeguards, documentation 

requirements, and procedures for 

registry operations that could be 

adapted to serve similar functions in 

relation to the final emission guidelines. 

For example, a key element of RPS 

compliance in many states that parallels 

the final rule’s requirements is that each 

generating unit must be uniquely 

identified and recorded in a specified 

registry to avoid the double counting of 

credits at the time of issuance and 

retirement. In addition, the existing 

reports and documentation from 

tracking systems may, together with 

eligible independent third party 

verification reports, serve as the 

substantive basis for eligibility 

applications, EM&V plans and M&V 

reports for the issuance of ERCs to 

energy generating resources for affected 

EGUs to meet their obligations under 

the final rule. With respect to actual 

monitoring requirements, many existing 

REC registries include provisions for the 

monitoring of MWh of generation that 

would be appropriate to meet state plan 

requirements pursuant to the final rule, 

such as requirements to use a revenue 

quality meter. 

For demand-side EE, states must 

require that EM&V plans that are 

developed for purposes of adjusting an 

emission rate under this final rule 

include several specific components. 

The EPA notes these components reflect 

existing provisions in a wide range of 

publicly or rate-payer funded EE 

programs and energy service company 

projects. One of these components state 

plans must require is a demonstration of 

how savings will be quantified and 

verified by applying industry bestpractice protocols and guidelines, as 

well as an explanation of the key 

assumptions and data sources used. 

State plans must require EM&V plans to 

include and address the following: 

• A baseline that represents what would 

have happened in the absence of the EE 

intervention, such as the equipment that 

would most likely have been installed—or 

that a typical consumer or building owner 

would have continued using—in a given 

circumstance at the time of EE 

implementation 

• The effects of changes in independent 

factors affecting energy consumption and 

savings; that is, factors not directly related to 

the EE action, such as weather, occupancy, 

or production levels 

• The length of time the EE action is 

anticipated to continue to remain in place 

and operable, effectively providing savings 

(in years) 

Examples and discussion of industry 

best-practices for executing each of the 

above-listed components is provided in 

the EPA’s draft EM&V guidance for 

demand-side EE, which is being 

released in conjunction with the 

proposed model rule. The model trading 

rule defines certain EM&V provisions 

for demand-side EE, as well as specific 

provisions for non-affected CHP and RE 

resources, including incremental 

hydroelectric power, biomass RE 

facilities, and waste-to-energy facilities, 


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1003The emission standards in each individual 

state plan must include regulatory provisions that 

address the issuance of ERCs and tracking of ERCs 

from issuance through use for compliance, as 

described in section VIII.K.2. The description here 

addresses how those regulatory provisions will be 

implemented through the use of a joint tracking 

system, interoperable tracking systems, or an EPAadministered tracking system. 

1004States also have the option of implementing 

a multi-state plan with a single rate-based 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. 

1005This could be done by reference to data in the 

tracking system used to implement a state’s ratebased emission trading program that identifies the 

origin of each ERC (e.g., by serial identifier). 

1006The EPA would designate tracking systems 

that it has determined adequately address the 

integrity elements necessary for the issuance and 

tracking of ERCs, as described in section VIII.K.2. 

Under this approach, a state could include in its 

plan such a designated tracking system, which has 

already been reviewed by the EPA. 

1007The EPA notes that it is proposing a model 

rule for a rate-based emission trading program that 

could be used by states interested in implementing 

a ready-for-interstate-trading plan approach. A state 

plan that included the finalized rate-based model 

rule could be presumptively approvable as meeting 

the requirements of CAA section 111(d) and the 

emission guidelines. If a state plan also met the 

requirements described in this section for ready-forinterstate-trading plans, it could be approved as 

ready-for-interstate trading. 

that may be presumptively approvable 

upon finalization. 

The EPA notes that state plans 

incorporating the finalized model rule 

for rate-based emission trading 

programs could be presumptively 

approvable as meeting the requirements 

of CAA section 111(d) and the EM&V 

provisions in these emission guidelines. 

The EPA will evaluate the approvability 

of such state plans through independent 

notice and comment rulemaking. 

c. Skill certification standards. 

Using a skilled workforce to 

implement demand-side EE and RE 

projects and other measures intended to 

reduce CO2 emissions, and to evaluate, 

measure, quantify and verify the savings 

associated with EE projects or the 

additional generation from performance 

improvements at existing RE projects 

are both important in existing best 

industry practices. Several commenters 

pointed out that skill certification 

standards can help to assure quality and 

credibility of demand-side EE, RE, and 

other CO2 emission reduction projects. 

The EPA also recognizes that a skilled 

workforce performing the EM&V is 

important to substantiate the 

authenticity of emissions reductions. 

The EPA is therefore recommending 

in conjunction with the EM&V 

requirements discussed in this section, 

that states are encouraged to include in 

their plans a description of how states 

will ensure that the skills of workers 

installing demand-side EE and RE 

projects or other measures intended to 

reduce CO2 emissions as well as the 

skills of workers who perform the 

EM&V of demand-side EE and RE 

performance will be certified by a third 

party entity that: 

(1) Develops a competency based program 

aligned with a job task analysis and 

certification scheme; 

(2) Engages with subject matter experts in 

the development of the job task analysis and 

certification schemes that represent 

appropriate qualifications, categories of the 

jobs, and levels of experience; 

(3) Has clearly documented the process 

used to develop the job task analysis and 

certification schemes, covering such 

elements as the job description, knowledge, 

skills, and abilities; 

(4) Has pursued third-party accreditation 

aligned with consensus-based standards, for 

example ISO/IEC 17024. 

Examples of such entities include: 

Parties aligned with the Department of 

Energy’s (DOE) Better Building 

Workforce Guidelines and validated by 

a third party accrediting body 

recognized by DOE; or by an 

apprenticeship program that is 

registered with the federal Department 

of Labor (DOL), Office of 

Apprenticeship; or with a state 

apprenticeship program approved by 

the DOL, or by another skill certification 

validated by a third party accrediting 

body. This can help to substantiate the 

authenticity of emission reductions due 

to demand-side EE and RE and other 

CO2 emission reduction measures. 

4. Multi-State Coordination: Rate-Based 

Emission Trading Programs 

Individual rate-based state plans may 

provide for the interstate transfer of 

ERCs, which would enable an ERC 

issued by one state to be used for 

compliance by an affected EGU with a 

rate-based emission standard in another 

state. Such plans would include 

regulatory provisions in each state’s 

emission standard requirements that 

indicate that ERCs issued in other 

partner states may be used by affected 

EGUs for compliance. Such plans must 

indicate how ERCs will be tracked from 

issuance through use for compliance, 

through either a joint tracking system, 

interoperable tracking systems, or an 

EPA-administered tracking system.1003

The approaches described in this 

section are only allowed for states that 

impose rate-based emission limits for 

affected EGUs that are equal to the CO2

emission performance levels in the 

emission guidelines. This approach is 

necessary to ensure that each state that 

is allowing for the interstate transfer of 

ERCs is implementing rate-based 

emission standards for affected EGUs at 

the same lb CO2/MWh level.1004 This 

assures that all the participating states 

are issuing ERCs to affected fossil steam 

and NGCC units that emit below their 

assigned emission standards on the 

same basis. 

This approach avoids providing 

different incentives, in the form of 

issued ERCs, to affected steam 

generating units and NGCC units in 

different states that have comparable 

CO2 emission rates. Providing different 

incentives to similar affected EGUs 

across states could create distortionary 

effects that lead to shifts in generation 

among states based on the different CO2

emission rate standards applied by 

states to similar types of affected EGUs. 

Providing for the interstate trading of 

ERCs in this instance would exacerbate 

these distortionary effects by providing 

arbitrage opportunities. 

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.1005

States could implement these linkages 

among state plans with rate-based 

emission trading systems through three 

different implementation approaches: 

(1) Plans that are ‘‘ready-for-interstatetrading;’’ (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-approved 1006 or EPAadministered 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.1007

• 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 EPAadministered 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 


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1008This refers to eligibility applications and 

M&V reports, which are required submittals for 

non-affected EGU entities seeking the issuance of 

ERCs. Where affected EGUs are issued ERCs for 

emission performance below a specified CO2

emission rate, these ERCs are issued by the 

individual state in which they are subject to a ratebased emission standard. Requirements for ERC 

issuance are discussed in section VIII.K.2. 

1009The EPA also notes that individual state 

plans may utilize RE and demand-side EE (and 

other eligible measures), that occur in other states, 

as described in section VIII.L addressing interstate 

effects. Under an individual state plan, ERCs could 

be issued for RE and demand-side EE measures that 

occur in other states, provided the EE/RE provider 

submits the measures to the state and the measures 

meet requirements in the state plan’s rate-based 

emission trading program requirements. The multistate approaches described above provide 

additional flexibility for states to informally and 

formally coordinate their implementation of ratebased plans across states while retaining individual 

rate-based state goals. 

1010This section does not discuss emission 

leakage and how it is addressed by this final rule. 

See section VII.D for a discussion of emission 

leakage and its impact on state goal equivalence. 

See section VIII.J for a discussion of requirements 

for mass-based plans to address leakage. 

trading program regulations and share a 

tracking system. States coordinate their 

review of submissions for ERC issuance 1008

and their issuance of ERCs to the shared 

tracking system. Issued ERCs are recognized 

as usable for compliance in all states using 

the shared tracking system. Plans are 

approved individually, including review of 

the shared tracking system. 

These implementation approaches are 

designed to streamline the process for 

linking emission trading programs, 

avoid or limit the need for plan 

revisions as new states join a 

collaborative emission trading 

approach, and facilitate the 

development of regional or broader 

multi-state markets for ERCs.1009

L. Treatment of Interstate Effects 

This section discusses how differing 

characteristics across states and sources 

could create risks of increased 

emissions under this rule through 

double counting of emission reduction 

measures or through foregone emission 

reductions due to movement of 

generation from source to source. The 

section also discusses how the final rule 

addresses these concerns: First, through 

the characteristics of goal-setting and 

the framework of state plans, and 

second, through specific requirements 

intended to minimize the risk of double 

counting and increased emissions.1010

The section is structured as follows. 

First, this section discusses the 

dynamics that cause these risks to 

potentially arise. Second, it provides a 

discussion of how the risks of double 

counting and foregone reductions are 

minimized through the following 

provisions: The nature of the final 

emission performance rates, multi-state 

plan options that limit distortionary 

effects, the structure of mass-based plan 

and rate-based plan accounting for 

emission reductions measures, and 

specified restrictions on the counting in 

a rate-based plan of emission reduction 

measures located in a mass-based state. 

Finally, the section discusses how the 

rate-based accounting framework 

minimizes incentives to develop 

emission reduction measures in 

particular states due to differences in 

rates. 

In the June 2014 proposal, the EPA 

acknowledged that emission reduction 

measures implemented under a state 

plan will likely have impacts across 

many affected sources both within and 

across state boundaries due to the 

dynamic and interstate nature of the 

electric grid. These interactions may be 

driven in part due to differences in 

power sector dynamics across states, 

including the types of affected EGUs in 

a state, the availability of eligible zeroemitting resources, and the costs of 

different compliance options and 

existing policies in states. These statelevel characteristics play out across 

dynamic regional grids that provide 

electricity across states. EGUs are 

dispatched both within and across state 

borders and are constantly adjusting 

behavior in response to available 

generation and electricity demand on 

the regional grid. Whenever CO2

emission reduction measures, such as 

RE or demand-side EE, are 

implemented, the measure can affect 

EGU generation and CO2 emissions 

across the regional grid. These impacts 

can change across multiple affected 

EGUs on a minute-to-minute, hour-tohour, and day-to-day basis as electricity 

demand changes and different 

generating resources are dispatched. 

These impacts will also change in the 

long-term, as the generating fleet and 

load behavior change over a period of 

years. Interactions among EGUs across 

states may be further driven by the plan 

types (i.e., rate-based or mass-based) and 

the individual characteristics of the 

plans that states choose to adopt. 

In the context of this complex 

environment of federal and state 

policies and interstate grids, 

commenters expressed concern about 

the risk of double-counting of measure 

impacts, particularly across state plans. 

Commenters stated that there is 

potential for distortionary incentives 

that could undermine overall CO2

emission reductions (often termed 

emissions ‘‘leakage’’). Commenters 

requested that the EPA ensure that 

states avoid double-counting and 

minimize leakage effects when 

demonstrating achievement of state 

goals. 

The EPA acknowledges that some 

amount of shifts in generation between 

sources within and across state borders 

will inevitably be present and 

unavoidable in the context of this rule 

and may affect how affected EGUs 

achieve the applicable CO2 performance 

rates or state goals under a state plan. In 

fact, the definition of the BSER is 

premised upon shifts in generation 

across sources, particularly shifts from 

higher- to lower-emitting units that 

result in overall emission reductions. 

However, in the context of these shifts, 

the extent to which the movement of 

generation may be driven not by the 

potential to capture lower-cost emission 

reduction but by arbitrage across 

different emission rates, causing 

inefficiencies in the power markets and 

possibly eroding overall emission 

reductions, should be minimized. 

In particular, the EPA has determined 

final emission performance rates that 

serve to reduce relative differences 

between state goals, and thus also focus 

the potential for generation shifting 

between affected EGUs on achieving the 

emission reductions quantified in the 

BSER. In the proposal, goals differed 

more substantially between states based 

upon an assessment of what emission 

reduction potential units could access 

located within their state. Commenters 

observed that due to the interconnected 

nature of the power sector, units are not 

limited to such emission reduction 

measures within their state, and indeed 

any operational decisions that units take 

necessarily influence operational 

decisions at other units throughout the 

interconnected grid. As a result, in the 

final rule, we are finalizing CO2

emission performance rates, informed 

by regional emission reduction 

potential, for fossil fuel-fired electric 

utility steam generating units and 

stationary combustion turbines that are 

applied consistently across all affected 

EGUs. As the same source categoryspecific performance rates are applied to 

all units in the contiguous U.S. 

regardless of the state in which they are 

located, any differences between state 

goals in this final rule stem only from 

the relative prevalence in each state of 

fossil fuel-fired electric utility steam 

generating units and stationary 

combustion turbines. Consequently, 

there is substantially less incentive in 

this final rule for units to shift 

generation across state lines based 

solely on differences in state goals, since 

there is substantially less difference 

between the final rule’s state goals, and 

since those state goals are themselves 

premised on nationally consistent 


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source category-specific performance 

rates. 

The EPA has also incorporated 

elements into the rule that seek to 

minimize double-counting and the 

distortionary effects that could 

potentially increase emissions. First, 

states have the option to adopt multistate plans that reflect regional 

interactions while eliminating chances 

for double counting and providing a 

level playing field for trading of ratebased ERCs or mass-based allowances. 

Second, in the method for rate-based 

plan compliance, the rule provides a 

general accounting approach for 

adjusting an affected EGU’s or state’s 

CO2 rate that inherently acts to 

minimize state differences. These points 

are further discussed below. 

For both rate-based and mass-based 

approaches, the rule provides states 

with the option of creating either 

‘‘ready-for-interstate-trading’’ plans or 

multi-state plans. These options for 

states working together provide 

opportunities to enable protections 

against double counting and minimize 

the presence of distortionary effects. 

‘‘Ready-for-interstate-trading’’ and 

multi-state plans engage multiple states 

in the same system for the purpose of 

trading mass-based allowances or 

issuing and trading rate-based ERCs. 

This allows for efficient implementation 

of protections against double counting 

provided in state plan requirements, as 

multiple states are participating in the 

same tracking systems. This is 

particularly useful in the context of ratebased ERC issuance and tracking, where 

it must be ensured that the ERCs being 

generated are unique across rate-based 

plans. 

This final rule also reduces 

distortionary effects within the context 

of multi-state plans. It does so by 

restricting states to interstate trading 

with equivalently denominated massbased allowances or rate-based ERCs. In 

a mass-based context, all affected EGUs 

will trade uniform mass-based 

allowances, whether in a ‘‘ready-forinterstate-trading’’ plan or multi-state 

plan. In a rate-based plan context, 

‘‘ready-for-interstate-trading’’ states 

must all adopt as their goal the CO2

emission performance rates as their joint 

goal. This assures that all the 

participating states are issuing ERCs 

using the same subcategorized 

performance rates, and that the sources 

in each state have equivalent incentives 

for trading ERCs. Similarly, under 

multi-state plans, the relevant states 

must choose to adopt identical rates, 

either the CO2 emission performance 

rates or a weighted average goal rate 

based on the rate-based goals of all the 

states involved. These requirements 

along with a method for calculating a 

weighted average goal rate are specified 

in section VIII.C.5. 

Under all types of state plans, states 

must ensure that the emission reduction 

measures counted as part of meeting 

their plan requirements are not 

duplicative of any measures that are 

counted by another state, in order to 

avoid double counting of the MWhs of 

generation or energy savings that these 

measure produce. Depending on the 

accounting method used to reflect these 

measures in state goals, interstate effects 

could still allow for the double counting 

of the emission reductions resulting 

from these measures, particularly if 

mathematical adjustments were made to 

stack emissions to reflect these 

reductions. Depending on how these 

measures are accounted for, the 

reductions could be counted by both the 

state that deployed the measure, and the 

state that reports a reduction in fossil 

generation or reported emissions. In this 

final rule, the accounting approaches for 

both mass-based and rate-based plans 

have been specifically designed to 

eliminate the risk of double counting of 

reductions, because emission reduction 

measures are accounted for only 

through their inherent impact on stack 

emissions for affected EGUs. 

Mass-based plans rely exclusively on 

reported stack emissions for 

determining whether a mass-based CO2

emission goal is achieved. This means 

that under a mass-based plan any 

emission reduction measures that are 

implemented are automatically 

accounted for in reduced stack 

emissions of CO2 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 lowor zero-emitting generation or energy 

savings for affected EGU generation. 

States with rate-based plans must 

demonstrate that measures used to 

adjust their CO2 emission rate, such as 

RE and demand-side EE, are nonduplicative. 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 instate measures still have an impact 

outside of the state and under the 

proposal’s approach, states would have 

been restricted from taking credit for all 

the measures they have put in place that 

reduce CO2 emissions. Therefore, the 

EPA is finalizing a treatment that allows 

states to count all in-state and out-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.K.1 above, used to show that the 

state has met its obligation under its 

state plan. 

The general accounting approach for 

adjusting the CO2 emission rate of an 

affected EGU inherently accounts for the 

regional nature of how substitute 

generation and energy savings will 

impact affected EGU generation and CO2

emissions. The following discussions 

refer to the substituting generation and 

energy savings in question as RE and 

demand-side EE, but this method can 

apply to other measures that were not 

included in the determination of the 

BSER that substitute for affected EGU 

generation. The adjusted CO2 emission 

rate gives credit to the affected EGU or 

state for the MWhs of RE and demandside EE it is responsible for deploying, 

by allowing those MWhs to be added to 

the denominator of the CO2 rate, but 

makes no adjustment to the numerator. 

Instead, the numerator reflects reported 

stack emissions, which will reflect the 

extent to which RE and demand-side EE 

reduced the affected EGU’s generation 

and emissions, without needing to 

account for the state in which the RE or 

demand-side EE originated, or 

approximating exactly how it impacted 

the regional grid. Double-counting of 

CO2 emission reductions is prevented 

because the reported emissions from 

each unit are represented in the 

numerator of each of those units’ 

emission rates, and those real emissions 

capture whatever emission reduction 

impact occurred with regard to any 

particular MWh of RE or demand-side 

EE. Because the general accounting 

approach disallows any adjustment to 

any EGU’s reported emissions, it is not 

possible for the real emission reductions 

prompted by any particular measure to 

be double-counted. 

Double-counting of MWhs in the 

denominator can be avoided because it 

is relatively straightforward to quantify 

the MWhs that the affected EGU is 

responsible for deploying and add them 

to the denominator, and this method 

aligns well with the MWh-denominated 

trading system described in this final 

rule. As long as it is assured that the 

MWhs of RE and demand-side EE are 

only being claimed by one affected EGU 

or state, as is outlined in section VIII.K, 

then there is no double-counting of 

MWh. Therefore, the accounting method 

avoids double counting of both CO2

emission reductions and MWhs, the two 

characteristics of RE and demand-side 

EE measures that affect CO2 emission 

rates. For further discussion of the 


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1011This 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. 

MWh-based accounting method, 

including a calculation example, see 

section VIII.K.1. 

There may also be interactions 

between mass-based and rate-based 

plans regarding counting measures, 

specifically where measures that 

provide substitute or avoided 

generation, such as RE and demand-side 

EE, are located in a mass-based state and 

can also be used by a rate-based state in 

meeting the CO2 performance rates or 

state goals. The EPA received comments 

on this particular issue, and many 

expressed concerns that this use of 

mass-based resources in a rate-based 

state would result in double-counting of 

emission reductions. 

Commenters provided analyses 

specifying how two states can benefit 

from the same RE and demand-side EE 

measures as a result of rate- and massbased plan interactions. Some 

commenters considered this doublecounting of emission reductions, and 

requested specific mathematical 

adjustments of reported generation or 

CO2 emissions from affected EGUs 

under either rate-based 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 massbased 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 the reported CO2

emission rate. The CO2 emissions 

impacts of the measures will be 

reflected in the rate-based state only to 

the extent that the MWhs resulted in 

lower reported CO2 emissions from an 

affected EGU in the rate-based state. To 

the extent that measures that provide 

substitute or avoided generation reduce 

generation from affected EGUs in a 

mass-based state, the effect of those 

measures is reflected in lower reported 

CO2 emissions of the mass-based EGUs. 

The CO2 emission reductions reflected 

in the rate and the mass state will 

necessarily be mutually exclusive, 

because both are based on reported 

stack emissions. Additionally, the 

mechanism in the mass-based state that 

is assuring CO2 emission reductions is 

the mass budget, which is met by 

affected EGUs adjusting 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 double-counting of 

emission reductions can take place. 

Though there is no risk of doublecounting emissions, some commenters 

expressed the concern that overall CO2

emissions reductions would be foregone 

in situations where a source in a ratebased state counts the MWh from 

measures in a mass-based state, but the 

generation from that measure acts solely 

to serve load in the mass-based state. In 

that scenario, expected CO2 emission 

reduction actions in the rate-based state 

are foregone as a result of counting 

MWh that resulted in CO2 emission 

reductions in a mass-based state. 

Therefore the EPA is restricting the 

ability of rate-based states to claim 

emission reduction measures, such as 

RE and demand-side EE, located in 

mass-based states. 

While the EPA understands this 

concern regarding foregone reductions, 

we do not believe it is appropriate to 

restrict RE crediting unilaterally 

between rate-based and mass-based 

states. Such a restriction could cut some 

states off from regional RE supplies that 

are assumed in the BSER building block 

3 and incorporated in the CO2 emission 

performance rates and state CO2 goals. 

Allowing crediting between rate- and 

mass-based states, 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 massbased states, subject to the condition 

that the generation in question was 

intended to meet electricity load in a 

state with a rate-based plan.1011 This 

may apply to some or all of the 

generation from an individual RE 

installation. To assure that the RE 

generation in question meets this 

condition, the EPA is requiring that RE 

generation from RE installations located 

in a mass-based state can only be 

counted in a rate-based state if the 

electricity generated is delivered with 

the intention to meet load in a state with 

a rate-based plan, and was treated as a 

generation resource used to serve 

regional load that included the ratebased 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. 

The following are examples of how 

requirements for a demonstration could 

be established in state plans and used to 

allow RE in a mass-based state to be 

counted in a rate-based state. For an 

emission standards state plan, a state 

could specify in the regulations for the 

rate-based emission standards included 

in its state plan that it will require an 

RE provider that seeks the issuance of 

ERCs to show that load-serving entities 

in the rate-based state have contracted 

for the delivery of the RE generation that 

occurs in a mass-based state to meet 

load in a rate-based state. Under this 

approach, an RE provider in a massbased state could submit as part of an 

eligibility application a delivery 

contract or power purchase agreement 

showing that the generation was 

procured by the utility, and was treated 

as a generation resource used to serve 

regional load that included the ratebased 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 

M&V reports submitted for issuance of 

ERCs. 

The ability for a rate-based state to 

count MWhs located in a mass-based 

state under the above conditions is 

limited to RE. Rate-based states are not 

allowed to claim demand-side EE or any 

other emission reduction measures that 

were not included in the determination 

of the BSER located in mass-based states 

for ERC issuance. While this limits ratebased sources’ access to additional 

resources, providing that access would 

result in a risk of foregone reductions. 

Further, unlike RE, there is no 

obligation related to demand-side EE 

and other measures that were not 

included in the determination of the 

BSER incorporated in the CO2 emission 

performance rates or state rate-based 

goals which would necessitate 

facilitating access to those resources. 

This treatment also does not apply to 


tkelley on DSK3SPTVN1PROD with BOOK 2
64914 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1012 In this preamble, the EPA discusses 

environmental justice in two sections. Section XI.J 

specifically addresses how the agency has met the 

directives under Executive Order 12898. The EPA 

defines environmental justice as the fair treatment 

and meaningful involvement of all people 

regardless of race, color, national origin or income 

with respect to the development, implementation, 

and enforcement of environmental laws, 

regulations, and policies. This section of the 

preamble addresses actions that the agency is taking 

related to environmental justice and other issues 

(e.g., increased electricity costs) that may affect 

communities covered by Executive Order 12898 as 

well as other communities. 

1013Six Common Air Pollutants. http://

www.epa.gov/oaqps001/urbanair/. 

fossil-fuel fired EGUs, such as NGCC 

units. If a mass-based emission standard 

has been applied to an affected EGU, 

there is no valid way to calculate 

whether it has MWh that are eligible for 

crediting, as is possible under a ratebased plan. 

Finally, as stated earlier, commenters 

also expressed concern about the 

potential for relative increases in 

emissions to occur given relative 

differences between sources and states. 

These differences could include states’ 

goals under either the rate- or massbased 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. 

Commenters suggested that the 

issuance and trading of emission credits 

across states under a rate-based 

approach would result in incentives to 

create credits, through the development 

of RE for example, in certain states with 

higher state goals, and this could also be 

a source of increased overall emissions. 

They noted that RE siting would thus 

not occur in the most optimal locations. 

The commenters assumed that zeroemitting 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, zeroemitting MWhs would create more 

mass-denominated credits in those 

states, and thus RE and demand-side EE 

would be more valuable. 

The incentive to target the location of 

zero-emitting generation or energy 

savings between states based on 

variation in its emission reduction value 

has been minimized by the fact that 

states participating in rate-based 

interstate trading must adopt the same 

emission performance rates or ratebased state goals. It is further 

minimized, even outside of an interstate 

trading framework, by the nature of the 

accounting method finalized in this 

rule. As explained above regarding the 

general accounting approach and the 

trading framework, we are adjusting 

rates using calculated MWhs, not based 

upon an emission reduction 

approximation as commenters outlined 

above. Not only does the method allow 

emission reductions to be accounted for 

as they occur across the grid, but it 

means the ERCs being traded across 

states represent one MWh of zeroemitting generation in whatever state it 

originated, and its value is unaffected by 

any emission rate associated with its 

state of origin. Thus, the finalized 

accounting and trading methods 

minimize the relative incentives for 

generating zero-emitting ERCs in a 

particular state based upon the rates that 

apply to that state. 

IX. Community and Environmental 

Justice Considerations 

In this section we provide an 

overview of the actions that the agency 

is taking to help ensure that vulnerable 

communities are not disproportionately 

impacted by this rulemaking.1012As 

described in the Executive Summary, 

climate change is an environmental 

justice issue. Low-income communities 

and communities of color already 

overburdened with pollution are likely 

to be disproportionately affected by, and 

less resilient to, the impacts of climate 

change. This rulemaking will provide 

broad benefit to communities across the 

nation, as its purpose is to reduce GHGs, 

the most significant driver of climate 

change. While addressing climate 

change will provide broad benefits, it is 

particularly beneficial to low-income 

populations and some communities of 

color (in particular, populations defined 

jointly by ethnic/racial characteristics 

and geographic location) where people 

are most vulnerable to the impacts of 

climate change (a more robust 

discussion of the impacts of climate 

change on vulnerable communities is 

provided in the Executive Order 12898 

section XII.J of this preamble). While 

climate change is a global phenomenon, 

the adverse effects of climate change can 

be very localized, as impacts such as 

storms, flooding, droughts, and the like 

are experienced in individual 

communities. 

Vulnerable communities also often 

receive more than their fair share of 

conventional air pollution, with the 

attendant adverse health impacts. The 

changes in electricity generation that 

will result from this rule will further 

benefit communities by reducing 

existing air pollution that directly 

contributes to adverse localized health 

effects. These air quality improvements 

will be achieved through this rule 

because the electric generating units 

that emit the most GHGs also have the 

highest emissions of conventional 

pollutants, such as SO2, NOX, fine 

particles, and HAP. These pollutants are 

known to contribute to adverse health 

outcomes, including the development of 

heart or lung diseases, such as asthma 

and bronchitis, increased susceptibility 

to respiratory and cardiac symptoms, 

greater numbers of emergency room 

visits and hospital admissions, and 

premature deaths.1013 The EPA expects 

that the reductions in utilization of 

higher-emitting units likely to occur 

during the implementation of state 

plans will produce significant 

reductions in emissions of conventional 

pollutants, particularly in those 

communities already overburdened by 

pollution, which are often low-income 

communities, communities of color, and 

indigenous communities. These 

reductions will have beneficial effects 

on air quality and public health both 

locally and regionally. Further, this 

rulemaking complements other actions 

already taken by the EPA to reduce 

conventional pollutant emissions and 

improve health outcomes for 

overburdened communities. 

By reducing millions of tons of CO2

emissions that are contributing to global 

GHG levels and providing strong 

leadership to encourage meaningful 

reductions by countries across the globe, 

this rule is a significant step to address 

health and economic impacts of climate 

change that will fall disproportionately 

on vulnerable communities. By 

reducing millions of tons of 

conventional air pollutants, the rule will 

lead to better air quality and improved 

health in those communities. We heard 

from many commenters who recognize 

and welcome those benefits. 

There are other ways in which the 

actions that result from this rulemaking 

may affect communities in positive or 

potentially adverse ways and we also 

heard about these from commenters. 

While the agency expects overall 

emission decreases as a result of this 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64915 

1014 Detailed information on the outreach 

conducted as part of this rulemaking is provided in 

section I of this preamble. 

1015The proximity analysis was conducted using 

the EPA’s environmental justice mapping and 

screening tool, EJSCREEN. 

rulemaking, we recognize that some 

EGUs may operate more frequently, as a 

result of this rulemaking. To the extent 

that we project increases in utilization 

as a result of this rulemaking, we expect 

these increases to occur generally in 

lower-emitting NGCC units, which have 

minimal or no emissions of SO2 and 

HAP, lower emissions of particulate 

matter, and much lower emissions of 

NOX compared to higher-emitting steam 

units. We acknowledge the concerns 

that have been raised on this point but 

also the difficulty in anticipating prior 

to plan implementation where those 

impacts might occur. In addition to 

providing for a robust state planning 

process with opportunity for meaningful 

input, the EPA is encouraging states to 

evaluate the actual impacts of their 

plans once implemented and, as 

described below, the EPA intends to 

conduct an assessment of whether and 

where emission increases may that may 

result from plan implementation and to 

work with states to mitigate adverse 

impacts, if any, in overburdened 

communities. 

In addition to the many positive 

anticipated health benefits of this 

rulemaking, it also will increase the use 

of clean energy and will encourage EE. 

These changes in the electricity 

generation system, which are already 

occurring but may be accelerated by this 

program, are expected to have other 

positive benefits for communities. The 

electricity sector is, and will continue to 

be, investing more in RE and EE. The 

construction of renewable generation 

and the implementation of EE programs 

such as residential weatherization will 

bring investment and employment 

opportunities to the communities where 

they take place. We recognize that 

certain communities whose economies 

may be affected by changes in the utility 

and related sectors may be particularly 

impacted by the final rule. The EPA 

encourages states to make an effort to 

engage with these communities, 

including workers and their 

representatives in these sectors, 

including EE. It is important to ensure 

that all communities share in the 

benefits of this program. And while we 

estimate that its benefits will greatly 

exceed its costs (as noted in the RIA for 

this rulemaking), it is also important to 

ensure that to the extent there are 

increases in electricity costs, that those 

do not fall disproportionately on those 

least able to afford them. 

The EPA has engaged with 

community groups throughout this 

rulemaking, and we received many 

comments on the issues outlined above 

from community groups, environmental 

justice organizations, faith-based 

organizations, public health 

organizations, and others.1014 This input 

has informed this final rulemaking and 

prompted the EPA to consider other 

steps that the agency can take in the 

short and long term to assist states and 

stakeholders to consider environmental 

justice and impacts to communities in 

plan development and implementation. 

It has also prompted us to work with 

our federal partners to make sure that 

states and communities have 

information on federal resources 

available to assist communities. We 

describe these resources below, as well 

as resources that the EPA will be 

providing to assist communities in 

accessing EE/RE and financial 

assistance programs. In our discussion 

below we also provide models of 

programs that other states are currently 

using to assist communities in accessing 

available resources that states could use 

when developing their plans. 

Finally, and importantly, we 

recognize that communities must be 

able to participate meaningfully in state 

plan development. In this section, we 

discuss the requirements in the final 

rule for states, as they develop their 

plans, to provide opportunities for 

public involvement, and resources 

available to states and communities to 

enhance the success of the public 

process. 

A. Proximity Analysis 

The EPA is committed to assisting 

states and communities to develop 

plans that ensure there are no 

disproportionate, adverse impacts on 

overburdened communities. To provide 

information fundamental to beginning 

that process, the EPA has conducted a 

proximity analysis for this final 

rulemaking that summarizes 

demographic data on the communities 

located near power plants.1015 The EPA 

understands that, in order to prevent 

disproportionately, high and adverse 

human health or environmental effects 

on these communities, both states and 

communities must have information on 

the communities living near facilities, 

including demographic data, and that 

accessing and using census data files 

requires expertise that some community 

groups may lack. Therefore, the EPA 

used census data from the American 

Community Survey (ACS) 2008–2012 to 

conduct a proximity analysis that can be 

used by states and communities as they 

develop state plans and as they later 

assess the final plans’ impacts. The 

analysis and its results are presented in 

the EJ Screening Report for the Clean 

Power Plan, which is located in the 

docket for this rulemaking at EPA–HQ– 

OAR–2013–0602. 

The proximity analysis provides 

detailed demographic information on 

the communities located within a 3-mile 

radius of each affected power plant in 

the U.S. Included in the analysis is the 

breakdown by percentage of community 

characteristics such as income and 

minority status. The analysis shows a 

higher percentage of communities of 

color and low-income communities 

living near power plants than national 

averages. It is important to note that the 

impacts of power plant emissions are 

not limited to a 3-mile radius and the 

impacts of both potential increases and 

decreases in power plant emissions can 

be felt many miles away. Still, being 

aware of the characteristics of 

communities closest to power plants is 

a starting point in understanding how 

changes in the plant’s air emissions may 

affect the air quality experienced by 

some of those already experiencing 

environmental burdens. 

Although overall there is a higher 

fraction of communities of color and 

low-income populations living near 

power plants than national averages, 

there are differences between rural and 

urban power plants. There are many 

rural power plants that are located near 

small communities with high 

percentages of low-income populations 

and lower percentages of communities 

of color. In urban areas, nearby 

communities tend to be both lowincome communities and communities 

of color. In light of this difference 

between rural and urban communities 

proximate to power plants and in order 

to adequately capture both the lowincome and minority aspects central to 

environmental justice considerations, 

we use the terms ‘‘vulnerable’’ or 

‘‘overburdened’’ when referring to these 

communities. Our intent is for these 

terms to be understood in an expansive 

sense, in order to capture the full scope 

of communities, including indigenous 

communities most often located in rural 

areas, that 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
64916 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1016 Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. http://epa.gov/environmentaljustice/

resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. 

The EPA also believes that the 

information provided in the proximity 

analysis will promote engagement 

between vulnerable communities and 

their states and will be useful for states 

as they begin developing their plans. In 

addition to providing the proximity 

analysis in the docket of this 

rulemaking, the EPA will disseminate 

the proximity analysis to states and will 

make it publicly available on its Clean 

Power Plan (CPP) Community Portal. 

Furthermore, the EPA has also created 

an interactive mapping tool that 

illustrates where power plants are 

located and provides information on a 

state level. This tool is available at: 

http://cleanpowerplanmaps.epa.gov/

CleanPowerPlan/. 

Additionally, the EPA encourages 

states to conduct their own analyses of 

community considerations when 

developing their plans. Each state is 

uniquely knowledgeable about its own 

communities and well-positioned to 

consider the possible impacts of plans 

on vulnerable communities within its 

state. Conducting state-specific analyses 

would not only help states assess 

possible impacts of plan options, but it 

would also enhance a state’s 

understanding of the means to engage 

these communities that would most 

effectively reach them and lead to 

valuable exchanges of information and 

concerns. A state analysis, together with 

the proximity analysis conducted by the 

EPA, would provide a solid foundation 

for engagement between a state and its 

communities. 

Such state-specific analyses need not 

be exhaustive. An examination of the 

options a state is considering for its 

plan, and any projections of likely 

resulting increases in power plant 

emissions affecting low-income 

populations, communities of color 

populations, or indigenous 

communities, would be informative for 

communities. The analyses could 

include available air quality monitoring 

data and information from air quality 

models, and, if available, take into 

account information about local health 

vulnerabilities such as asthma rates or 

access to healthcare. Alternatively, a 

simple analysis may consider expected 

EGU utilization in geographic proximity 

to overburdened communities. The EPA 

will provide states with information on 

its publicly available environmental 

justice screening and mapping tool, EJ 

SCREEN, which they may use in 

conducting a state-specific analysis. The 

EPA will also provide states with 

resources containing examples of 

analyses that other states have 

conducted to examine the impacts of 

their programs on overburdened 

communities. Additionally, the EPA 

encourages states to submit a copy of 

their analysis if they choose to conduct 

one, with their initial and final plan 

submittals. 

B. Community Engagement in State Plan 

Development 

In sections VIII.D–E of this preamble, 

the EPA explains that states need to 

engage meaningfully with communities 

and other stakeholders during the initial 

and final plan submittal processes. 

Meaningful engagement includes 

outreach to vulnerable communities, 

sharing information and soliciting input 

on state plan development and on any 

accompanying assessments such as 

those described above, and selecting 

methods for engagement to support 

communities’ involvement at critical 

junctures in plan formulation and 

implementation. This engagement also 

includes providing the public the 

opportunity to comment on the state’s 

initial submittal and responding to 

significant comments received, 

including comments from vulnerable 

communities, as well as conducting a 

public hearing and responding to 

comments before a final state plan is 

submitted. Additionally, the EPA 

expects that states will conduct 

outreach meetings, which could include 

public hearings or listening sessions, 

before the initial submittal is made. The 

EPA also encourages states to provide 

background information about their 

proposed final state plan or their initial 

state plan in the appropriate languages 

in advance of their public hearing and 

at their public hearing. The EPA 

recommends that states provide 

translators and other resources at their 

public hearings, to ensure that members 

of the public can provide oral feedback. 

In the initial submittal, the final rule 

requires that states provide information 

to the agency about the community 

engagement they have undertaken and 

the means by which they intend to 

involve vulnerable communities and 

other stakeholders as they develop their 

final plan. Furthermore, as noted in 

section VIII.E of this preamble, in 

determining if states are eligible for a 2- 

year extension for submission of final 

plans, the rule requires that states 

demonstrate how they are meaningfully 

engaging vulnerable communities and 

other interested stakeholders as part of 

their public participation process. The 

EPA consulted its May 2015, Guidance 

on Considering Environmental Justice 

During the Development of Regulatory 

Actions, when crafting this rulemaking 

and recommends that states consult it to 

assist them in engaging meaningfully 

with vulnerable communities.1016

Additionally, states in their initial 

submittal and 2017 update must show 

how they identified the communities 

with whom they are engaging as they 

develop their plans. Some suggested 

actions that states could take to engage 

actively with the public, including 

conducting meaningful engagement 

with vulnerable communities, are 

outlined in section VIII.E of this 

preamble. Additionally, as outlined in 

section VIII.D, the final plan submitted 

by states must include an overview of 

the public hearing(s) conducted and 

information on how the state ensured 

that the hearing(s) were accessible to 

stakeholders including vulnerable 

communities. 

The EPA is committed to supporting 

states in effectively engaging with 

communities as they develop and 

implement their plans. The EPA will 

provide training and other resources 

throughout the implementation process 

that will assist states and communities 

in understanding plan requirements and 

options for plan development. These 

trainings will be a continuation of those 

that the EPA has already conducted 

with communities and states both preand post-proposal. The EPA will reach 

out to a wide variety of community 

stakeholders, including groups 

representing environmental justice 

communities, faith-based organizations, 

academic organizations working with 

vulnerable and overburdened 

communities, affordable housing 

advocates, public health professionals, 

public health organizations, and other 

community stakeholders. 

C. Providing Communities With Access 

to Additional Resources 

In addition to providing resources to 

states, the EPA encourages states to be 

aware of existing efforts undertaken by 

other states aimed at providing lowincome 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. The EPA encourages 

states to consider targeting economic 

development resources to communities 

that are likely to be negatively affected 

by ongoing changes in the utility and 

related sectors in support of efforts to 

diversify their economies, attract new 

sources of investment, and create new 

jobs. 

One example of a program targeted at 

low-income communities is the 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64917 

1017EmPOWER Maryland Low Income Energy 

Efficiency Programs (LIEEP). http://

www.mdhousing.org/Website/Programs/lieep/

Default.aspx. 

1018 Ibid. 

1019 Ibid. 

1020 Ibid. 

1021Energy Assistance. http://

www.dhr.state.md.us/blog/?page_id=4326. 

1022 Ibid. 

1023EmPower New York. http://

www.nyserda.ny.gov/All-Programs/Programs/

EmPower-New-York. 

1024Energy Outreach Colorado. http://

www.energyoutreach.org/about. 1025http://www.eda.gov/power. 

Maryland EmPOWER Low Income 

Energy Efficiency Program (LIEEP).1017

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.).1018

Funding for this program is provided by 

EmPOWER Maryland partners: 

Baltimore Gas and Electric, Southern 

Maryland Electric Cooperative, 

Delmarva Power, Allegheny Energy and 

Pepco.1019 This program is available to 

both homeowners and renters.1020

Additionally, the Maryland Department 

of Housing provides low-income 

families with home heating bill 

assistance and furnace repairs and 

replacements through the Maryland 

Energy Assistance Program (MEAP).1021

Maryland’s Electric Universal Service 

Program (EUSP) helps low-income 

electric customers with their electric 

bills.1022

Another example of a program is 

EmPower New York, which provides 

no-cost energy solutions to low-income 

populations.1023 Currently there are 

about 100,000 people who are receiving 

assistance. Both homeowners and 

renters are eligible to receive assistance 

under this program. The types of 

assistance available include EE 

upgrades (plugging leaks, adding 

insulation, replacing inefficient 

refrigerators and freezers and new 

energy-efficient lighting). Other states, 

like the State of Colorado’s Energy 

Outreach Colorado program, offer 

similar resources for low-income 

populations.1024

In 2013, the New York State Energy 

and Research Development Authority 

(NYSERDA) was able to secure a tripleA rated financial guarantee from the 

state’s Clean Water State Revolving 

Fund (SRF) for a $24 million bond 

issue. Proceeds funded residential EE 

loans that were available to all utility 

customers, including low-income 

households. SRF eligibility was based 

on the beneficial impact of EE 

investment in reducing atmospheric 

deposition on impaired water bodies 

consistent with Section 319 of the Clean 

Water Act. 

As discussed below, there are also 

many federal programs that can help 

low-income populations access the 

benefits of RE, EE, and the economic 

benefits of a cleaner energy economy. 

In the coming months, the EPA will 

continue to provide information and 

resources for communities and states on 

existing federal, state, local, and other 

financial assistance programs to 

encourage EE/RE opportunities that are 

already available to communities. For 

example the EPA will provide a catalog 

of current or recent state and local 

programs that have successfully helped 

communities adopt EE/RE measures. 

The goal of these resources is to help 

vulnerable communities gain the 

benefits of this rulemaking by 

encouraging that states use these types 

of tools in their state plans. The use of 

these RE/EE tools can also help lowincome 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 should try to 

assure that communities that may be 

expected to experience job losses can 

also take advantage of the opportunities 

for job growth or otherwise transition to 

healthy, sustainable economic growth 

(e.g., with regard to delivering EE 

measures and installing rooftop solar 

panels). Additionally, as part of the 

resources that we will be providing to 

states and low-income communities, the 

EPA will provide information on the 

Administration’s Partnerships for 

Opportunity and Workforce and 

Economic Revitalization (POWER) 

Initiative and other programs that 

specifically target economic 

development assistance to communities 

affected by changes in the coal industry 

and the utility power sector.1025

D. Federal Programs and Resources 

Available to Communities 

Federal agencies have a history of 

bringing EE and RE to low-income 

communities. Earlier this summer, the 

Administration announced a new 

initiative to scale up access to solar 

energy and cut energy bills for all 

Americans, in particular low- and 

moderate-income communities, and to 

create a more inclusive solar workforce. 

As part of this new initiative, the U.S. 

Department of Energy (DOE), the U.S. 

Department of Housing and Urban 

Development (HUD), U.S. Department of 

Agriculture (USDA), and the EPA 

launched a National Community Solar 

Partnership to unlock access to solar 

energy for the nearly 50 percent of 

households and businesses that are 

renters or do not have adequate roof 

space to install solar systems, with a 

focus on low- and moderate-income 

communities. The Administration also 

set a goal to install 300 megawatts (MW) 

of RE in federally subsidized housing by 

2020 and plants to provide technical 

assistance to make it easier to install 

solar energy on affordable housing, 

including clarifying how to use federal 

funding for EE and RE. To continue 

enhancing employment opportunities in 

the solar industry for all Americans, 

AmeriCorps is providing funding to 

deploy solar energy and create jobs in 

underserved communities, and DOE is 

working to expand solar energy 

education and opportunities for job 

training. 

These recent announcements build on 

the many existing federal programs and 

resources available to improve EE and 

accelerate the deployment of RE in 

vulnerable communities. Some 

examples of these resources include: the 

Department of Energy’s Weatherization 

Assistance Program, Health and Human 

Service’s Low Income Home Energy 

Assistance Program, the Department of 

Agriculture’s Energy Efficiency and 

Conservation Loan Program, High Cost 

Energy Grant Program, and the Rural 

Housing Service’s Multi-Family 

Housing Program. 

HUD supports EE improvements and 

the deployment of RE on affordable 

housing through its Energy Efficient 

Mortgage Program, Multifamily Property 

Assessed Clean Energy Pilot with the 

State of California, PowerSaver Program, 

and the use of Section 108 Community 

Development Block Grants. The 

Department of Treasury provides several 

tax credits to support RE development 

and EE in low-income communities, 

including the New Markets Tax Credit 

Program and the Low-Income Housing 

Tax Credit. The EPA’s RE-Powering 

America’s Land Initiative promotes the 

reuse of potentially contaminated lands, 

landfills and mine sites—many of which 

are in low-income communities—for RE 

through a combination of tailored 

redevelopment tools for communities 

and developers, as well as site-specific 

technical support. The EPA’s Green 


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1026 76 FR 48348. 

1027 76 FR 48347. 

1028 65 FR 79831. 1029 ‘‘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. 

Power Partnership is increasing 

community use of renewable electricity 

across the country and in low-income 

communities. The EPA partners with EE 

programs throughout the country that 

leverage ENERGY STAR to deliver 

broad consumer energy-saving benefits, 

of particular value to low-income 

households who can least afford high 

energy bills. ENERGY STAR also works 

with houses of worship to reduce energy 

costs—savings that can then be 

repurposed to their community mission, 

including programs and assistance to 

residents in low-income communities. 

The EPA will be working with these 

federal partners and others to ensure 

that states and vulnerable communities 

have access to information on these 

programs and their resources. 

The federal government also has a 

number of programs to expand 

employment opportunities in the energy 

sector, including for underserved 

populations. Examples of these include 

HUD, DOE, and the Department of 

Education’s ‘‘STEM, Energy, and 

Economic Development’’ program; 

DOE’s Diversity in Science and 

Technology Advances National Clean 

Energy in Solar (DISTANCE-Solar) 

Program; Grid Engineering for 

Accelerated Renewable Energy 

Deployment (GEARED); the Department 

of Labor’s Trade Adjustment Assistance 

Community College and Career Training 

(TAACCCT), Apprenticeship USA 

Advancing Apprenticeships in the 

Energy Field, Job Corps Green Training 

and Greening of Centers, and 

YouthBuild; and the EPA’s 

Environmental Workforce Development 

and Job Training (EWDJT) program. 

E. Multi-Pollutant Planning and CoPollutants 

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, 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 multipollutant approach has been suggested 

by states and regulated sources in past 

rulemakings as a tool to determine the 

best system of emission reductions. The 

EPA recommends that states consider 

such strategies in consultation with 

their communities, affected facilities, 

and other stakeholders. 

Air quality in a given area is affected 

by emissions from nearby sources and 

may be influenced by emissions that 

travel hundreds of miles and mix with 

emissions from other sources.1026 In the 

Cross-State Air Pollution Rule the EPA 

used its authority to reduce emissions 

that significantly contribute to 

downwind exposures. The RIA for the 

final Cross-State Air Pollution Rule 

anticipates substantial health benefits 

for the population across a wide region. 

Similarly, the EPA believes that, like the 

Cross-State Air Pollution Rule, this 

rulemaking will result in significant 

health benefits because it will reduce 

co-pollutant emissions of SO2 and NOX

on a regional and national basis.1027

Thus, localized increases in NOX

emissions may well be more than offset 

by NOX decreases elsewhere in the 

region that produce a net improvement 

in ozone and particulate concentrations 

across the area. 

Another effect of the final CO2

emission guidelines for affected existing 

fossil fuel-fired EGUs may be increased 

utilization of other, unmodified EGUs— 

in particular, high efficiency gas-fired 

EGUs—with relatively low GHG 

emissions per unit of electrical output. 

These plants may operate more hours 

during the year and could emit 

pollutants, including pollutants whose 

environmental effects would be 

localized and regional rather than global 

as is the case with GHG emissions. 

Changes in utilization already occur in 

response to energy 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 fuelfired units generally would not increase 

peak concentrations of PM2.5, NOX, or 

ozone around such EGUs to levels 

higher than those that are already 

occurring because peak hourly or daily 

emissions generally would not change; 

however, increased utilization may 

make periods of relatively high 

concentrations more frequent. It should 

be noted that the gas-fired sources likely 

to be dispatched more frequently have 

very low emissions of primary PM, SO2, 

and HAP per unit of electrical output 

and that they must continue to comply 

with other CAA requirements that 

directly address the conventional 

pollutants, including federal emission 

standards, rules included in SIPs, and 

conditions in Title V operating permits, 

in addition to the guidelines in this final 

rulemaking. Therefore, local (or 

regional) air quality for these pollutants 

is not likely to be significantly affected. 

For natural gas-fired EGUs, the EPA 

found that regulation of HAP emissions 

‘‘is not appropriate or necessary because 

the impacts due to HAP emissions from 

such units are negligible based on the 

results of the study documented in the 

utility RTC.’’ 1028 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 predict NOX

emissions from a NGCC unit to be 

approximately 10 times lower than a 

subcritical or supercritical coal-fired 

boiler.1029 Many, although not all, 

NGCC units are also very well 

controlled for emissions of NOX through 

the application of after combustion 

controls such as selective catalytic 

reduction. 

F. Assessing Impacts of State Plan 

Implementation 

It is important to the EPA that the 

implementation of state plans be 

assessed in order to identify whether 

they cause any adverse impacts on 

communities already overburdened by 

disproportionate environmental harms 

and risks. The EPA will conduct its own 

assessment during the implementation 

phase of this rulemaking to determine 

whether the implementation of state 

plans developed pursuant to this 

rulemaking and other air quality rules 

are, in fact, reducing emissions and 

improving air quality in all areas or 

whether there are localized air quality 

impacts that need to be addressed under 

other CAA authorities. Furthermore, the 


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1030 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. 1031Adaptive Management Plan for the Cap-andTrade Regulation. http://www.arb.ca.gov/cc/

capandtrade/adaptive_management/plan.pdf. 

October 2011. 

EPA recommends that states conduct 

evaluations of their own to determine 

the impacts of their plans on 

overburdened communities. An 

example of one such approach to 

assessing a state plan for reducing GHGs 

is the California Air Resources Board’s 

(CARB), First Update on the Climate 

Change Scoping Plan: Building on the 

Framework Pursuant to AB32: The 

California Global Warming Solutions 

Act of 2006, which outlines ongoing 

evaluations that it will conduct to 

determine the impacts of its programs 

(throughout the implementation stages) 

on overburdened communities.1030

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.1031 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 effects of copollutants, as well as training on how to 

develop and carry out these evaluations. 

This training will include guidance in 

accessing the publicly available 

information that sources and states 

currently report that can help with 

ongoing assessments of state plan 

impacts. For example, unit-specific 

emissions data and air quality 

monitoring data are readily available. 

This information, together with the 

assessment that the EPA will conduct in 

the implementation phase of this 

rulemaking and other analyses that 

states may develop, will enable states 

and communities to monitor any 

disproportionate emissions that may 

result in adverse impacts and to address 

them. 

G. EPA Continued Engagement 

The EPA is committed to helping 

ensure that this action will not have 

disproportionate adverse human health 

or environmental effects on vulnerable 

communities. Throughout the 

implementation phase of this 

rulemaking, the agency will continue to 

provide trainings and resources to assist 

communities and states as they engage 

with one another. Additionally, we will 

provide states with recommendations 

on best practices for engaging with 

vulnerable communities. The EPA, 

through its outreach efforts during 

implementation, will continue to solicit 

feedback from communities and states 

on topics for which they would like 

additional trainings and resources. 

The EPA will also provide states with 

resources containing examples of 

analyses that other states have 

conducted to examine the impacts of 

their programs on vulnerable 

communities, as well as information on 

its publicly available environmental 

justice screening and mapping tool, EJ 

SCREEN. States are encouraged to use 

this preliminary information as well as 

other available information to conduct 

their own analyses. As described above, 

the EPA will assess the impacts of this 

rulemaking during its implementation. 

The EPA will house this assessment, 

along with the proximity analysis and 

other information generated throughout 

the implementation process, on its 

Clean Power Plan (CPP) Community 

Portal that will be linked to this 

rulemaking’s Web site (www.epa.gov/

cleanpowerplan). In addition, the EPA 

has expanded its set of resources that 

are being developed to help states and 

communities understand the breadth of 

policy options and programs that have 

successfully brought EE/RE to 

overburdened communities. The EPA is 

committed to continuing its engagement 

with states and communities from the 

beginning of plan development through 

plan implementation. 

A more detailed discussion 

concerning the application of Executive 

Order 12898 in this rulemaking can be 

found in section XI.J of this preamble. 

A summary of the EPA’s interactions 

with communities is in the EJ Screening 

Report for the Clean Power Plan, 

available in the docket of this 

rulemaking. Furthermore, the EPA’s 

responses to public comments, 

including comments received from 

communities, are provided in the 

response to comments documents 

located in the docket for this 

rulemaking. 

In summary, the EPA in this final 

rulemaking has designed an integrative 

approach that helps to ensure that 

vulnerable communities are not 

disproportionately impacted by this 

rulemaking. The proximity analysis that 

the agency has conducted for this 

rulemaking is a central component of 

this approach. Not only is the proximity 

analysis a useful tool to help identify 

overburdened communities that may be 

impacted by this rulemaking, states can 

use this tool as they engage with 

communities in the development of 

their plans, consider a multi-pollutant 

approach, help low-income 

communities access EE/RE and financial 

assistance programs and assess the 

impacts of their state plans. 

Additionally, in order to continue to 

ensure that vulnerable communities are 

not disproportionately impacted by this 

rulemaking, the EPA will also be 

conducting its own assessment during 

the implementation phase. Furthermore, 

the EPA will continue to engage with 

communities and states throughout the 

implementation phase of this 

rulemaking to help ensure that 

vulnerable communities are not 

disproportionately impacted. 

X. Interactions With Other EPA 

Programs and Rules 

A. Implications for the New Source 

Review Program 

The new source review (NSR) 

program is a preconstruction permitting 

program that requires major stationary 

sources of air pollution to obtain 

permits prior to beginning construction. 

The requirements of the NSR program 

apply both to new construction and to 

modifications of existing major sources. 

Generally, a source triggers these 

permitting requirements as a result of a 

modification when it undertakes a 

physical or operational change that 

results in a significant emission increase 

and a net emissions increase. NSR 

regulations define what constitutes a 

significant net emissions increase, and 

the concept is pollutant-specific. As a 

result of the decision in Utility Air 

Regulatory Group (UARG) v. 

Environmental Protection Agency (EPA), 

134 S. Ct. 2427 (2014), a modification 

that increases only GHG emissions 

above the applicable level will not 

trigger the requirement to obtain a PSD 

permit. Under existing EPA regulations, 

a modifying major stationary source 

would trigger PSD permitting 

requirements for GHGs if it undergoes a 

change or change in the method of 

operation (modification) that results in 

a significant increase in the emissions of 

a pollutant other than GHGs and results 

in a GHG emissions increase of 75,000 

tons per year CO2e as well as a GHG 

emissions increase on a mass 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 


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1032Certain 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’’). 

facility is located or proposed to be built 

determine the specific permitting 

requirements. 

As part of its CAA section 111(d) 

plan, a state may impose requirements 

that require an affected EGU to 

undertake a physical or operational 

change to improve the unit’s efficiency 

that results in an increase in the unit’s 

dispatch and an increase in the unit’s 

annual emissions. If the emissions 

increase associated with the unit’s 

changes exceeds the thresholds in the 

NSR regulations for one or more 

regulated NSR pollutants, including the 

netting analysis, the changes would 

trigger NSR. 

While there may be instances in 

which an NSR permit would be 

required, we expect those situations to 

be few. As previously discussed in this 

preamble, states have considerable 

flexibility in selecting varied measures 

as they develop their plans to meet the 

goals of the emission guidelines. One of 

these flexibilities is the ability of the 

state to establish emission standards in 

their CAA section 111(d) plans in such 

a way so that their affected sources, in 

complying with those standards, in fact 

would not have emissions increases that 

trigger NSR. To achieve this, the state 

would need to conduct an analysis 

consistent with the NSR regulatory 

requirements that supports its 

determination that as long as affected 

sources comply with the emission 

standards in their CAA section 111(d) 

plan, the source’s emissions would not 

increase in a way that trigger NSR 

requirements. 

For example, a state could decide to 

use demand-side measures or increase 

reliance on RE as a way of reducing the 

future emissions of an affected source 

initially predicted (without such 

alterations) to increase its emissions as 

a result of a CAA section 111(d) plan 

requirement. In other words, a state 

plan’s incorporation of expanded use of 

cleaner generation or demand-side 

measures could yield the result that 

units that would otherwise be projected 

to trigger NSR through a physical 

change that might result in increased 

dispatch would not, in fact, increase 

their emissions, due to reduced demand 

for their operation. The state could also, 

as part of its CAA section 111(d) plan, 

develop conditions for a source 

expected to trigger NSR that would limit 

the unit’s ability to move up in the 

dispatch enough to result in a 

significant net emissions increase that 

would trigger NSR (effectively 

establishing a synthetic minor limit).1032

In addition, in this final rule, we have 

also adjusted the date of the period for 

mandatory reductions to 2022, instead 

of 2020, and provided states with 

flexibility with respect to the glide path. 

This obviates concerns that there is 

insufficient time for sources that may 

need permits to obtain them and allows 

additional planning time for these 

changes to be undertaken in a manner 

that does not trigger PSD. As a result of 

such flexibility and anticipated state 

involvement, we expect that a limited 

number of affected sources would 

trigger NSR when states implement their 

plans. 

B. Implications for the Title V Program 

In the preamble to the June 18, 2014 

proposal, the EPA discussed the issue of 

excessive title V fees resulting 

inadvertently as a consequence of the 

promulgation of the first section 111 

standard to regulate GHGs. Specifically, 

the EPA 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 emissionsbased 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 this issue of the 

Federal Register, the EPA is finalizing 

changes to the operating permits rules to 

address the title V fee issue. In 

particular, we are taking final action to 

exempt GHGs from emissions-based fee 

calculation requirements under the 

operating permit rules. In addition, we 

are also finalizing a modest GHG fee 

adjustment to recover the costs of 

addressing GHGs in permitting. The 

GHG adjustments we are finalizing are 

based on accounting for the number of 

permit actions that require a GHG 

assessment in a given period, rather 

than accounting for emissions levels of 

GHGs. Finally, the EPA is also finalizing 

the addition of text within 40 CFR part 

60, subpart TTTT, to clarify that the fee 

pollutant for operating permit purposes 

is GHG (as defined in 40 CFR 70.2 and 

71.2) to add clarity to our regulations 

and to avoid the potential need for 

possible future rulemakings to adjust 

the title V fee regulations if any 

constituent of GHG, other than CO2, 

becomes subject to regulation under 

CAA section 111 for the first time. 

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 this issue of the Federal 

Register). The title V fee issue is not an 

issue for any other subsequent CAA 

section 111 regulations, such as this 

section 111(d) standard; thus, there is 

no need to address any title V fee issues 

in this final rule as part of this action. 

In the proposal, the EPA discussed 

that the section 111 rules would have no 

effect on the applicability thresholds for 

GHG under the operating permit rules. 

After the proposal for this rulemaking 

was published, the U.S. Supreme Court 

issued its opinion in UARG v. EPA, 134 

S.Ct. 2427 (June 23, 2014), and in 

accordance with that decision, the D.C. 

Circuit subsequently issued an amended 

judgment in Coalition for Responsible 

Regulation, Inc. v. Environmental 

Protection Agency, Nos. 09–1322, 10– 

073, 10–1092 and 10–1167 (D.C. Cir., 

April 10, 2015). Those decisions 

support the same overall conclusion, as 

the EPA discussed in the proposal, with 

respect to the effect of this final section 

111 rule on the applicability thresholds 

for GHGs under the operating permits 

rules, though for different reasons. 

With respect to title V, the Supreme 

Court said that EPA may not treat GHGs 

as an air pollutant for purposes of 

determining whether a source is a major 

source required to obtain a title V 

operating permit. In accordance with 

that decision, the D.C. Circuit’s 

amended judgment vacated the title V 

regulations under review in that case to 

the extent that they require a stationary 

source to obtain a title V permit solely 

because the source emits or has the 

potential to emit GHGs above the 

applicable major source thresholds. The 

D.C. Circuit also directed the EPA to 

consider whether any further revisions 

to its regulations are appropriate in light 

of UARG v. EPA, and, if so, to undertake 

to make such revisions. These court 


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1033We 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. 

1034CWA 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. 

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.1033 The EPA recognizes the 

importance of assuring that each of the 

rules described below can achieve its 

intended environmental objectives in a 

commonsense, cost-effective manner, 

consistent with underlying statutory 

requirements, and while assuring a 

reliable power system. Executive Order 

13563, ‘‘Improving Regulation and 

Regulatory Review,’’ issued on January 

18, 2011, states that ‘‘[i]n developing 

regulatory actions and identifying 

appropriate approaches, each agency 

shall attempt to promote . . . 

coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve regulatory goals that are 

designed to promote innovation.’’ 

Within the EPA, we are paying careful 

attention to the interrelatedness and 

potential impacts on the industry, 

reliability and cost that these various 

rulemakings can have. 

1. Mercury and Air Toxics Standards 

(MATS) 

On February 16, 2012, the EPA issued 

the MATS rule (77 FR 9304) to reduce 

emissions of toxic air pollutants from 

new and existing coal- and oil-fired 

EGUs. The MATS rule will reduce 

emissions of heavy metals, including 

mercury, arsenic, chromium, and nickel; 

and acid gases, including hydrochloric 

acid and hydrofluoric acid. These toxic 

air pollutants, also known as hazardous 

air pollutants or air toxics, are known to 

cause, or suspected of causing, damage 

nervous system damage, cancer, and 

other serious health effects. The MATS 

rule will also reduce SO2 and fine 

particle pollution, which will reduce 

particle concentrations in the air and 

prevent thousands of premature deaths 

and tens of thousands of heart attacks, 

bronchitis cases and asthma episodes. 

New or reconstructed EGUs (i.e., 

sources that commence construction or 

reconstruction after May 3, 2011) 

subject to the MATS rule are required to 

comply by April 16, 2012 or upon 

startup, whichever is later. 

Existing sources subject to the MATS 

rule were required to begin meeting the 

rule’s requirements on April 16, 2015. 

Controls that will achieve the MATS 

performance standards are being 

installed on many units. Certain units, 

especially those that operate 

infrequently, may be considered not 

worth investing in given today’s 

electricity market, and are closing. The 

final MATS rule provided a foundation 

on which states and other permitting 

authorities could rely in granting an 

additional, fourth year for compliance 

provided for by the CAA. States report 

that these fourth year extensions are 

being granted. In addition, the EPA 

issued an enforcement policy that 

provides a clear pathway for reliabilitycritical units to receive an 

administrative order that includes a 

compliance schedule of up to an 

additional year, if it is needed to ensure 

electricity reliability. 

2. Cross-State Air Pollution Rule 

(CSAPR) 

The CSAPR requires states to take 

action to improve air quality by 

reducing SO2 and NOX emissions that 

cross state lines. These pollutants react 

in the atmosphere to form fine particles 

and ground-level ozone and are 

transported long distances, making it 

difficult for other states to attain and 

maintain the NAAQS. The first phase of 

CSAPR became effective on January 1, 

2015, for SO2 and annual NOX, and May 

1, 2015, for ozone season NOX. The 

second phase will become effective on 

January 1, 2017, for SO2 and annual 

NOX, and May 1, 2017, for ozone season 

NOX. Many of the power plants 

participating in CSAPR have taken 

actions to reduce hazardous air 

pollutants for MATS compliance that 

will also reduce SO2 and/or NOX. In this 

way these two rules are complementary. 

Compliance with one helps facilities 

comply with the other. 

3. Requirements for Cooling Water 

Intake Structures at Power Plants 

(316(b) Rule) 

On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the 

Clean Water Act (CWA) (33 U.S.C. 

1326(b)) (referred to hereinafter as the 

316(b) rule.) The rule was published on 

August 15, 2014 (79 FR 48300; August 

15, 2014), and became effective October 

14, 2014. The 316(b) rule establishes 

new standards to reduce injury and 

death of fish and other aquatic life 

caused by cooling water intake 

structures at existing power plants and 

manufacturing facilities.1034 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 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 sitespecific 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 


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new CCR landfills and surface 

impoundments under the Resource 

Conservation and Recovery Act, Subtitle 

D (42 U.S.C. 6941–6949a), 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 publiclyaccessible Web site. The final rule also 

supports the responsible recycling of 

CCRs by distinguishing safe, beneficial 

use from disposal. 

5. Steam Electric Effluent Limitation 

Guidelines and Standards (SE ELG Rule) 

The EPA is reviewing public 

comments and working to finalize the 

proposed SE ELG rule which will 

impact existing fossil fuel-fired EGUs. In 

2013, the EPA proposed the SE ELG rule 

(78 FR 34432; June 7, 2013) to 

strengthen the controls on discharges 

from certain steam electric power plants 

by revising technology-based effluent 

limitations guidelines and standards for 

the steam electric power generating 

point source category. The current 

regulations, which were last updated in 

1982, do not adequately address the 

toxic pollutants discharged from the 

electric power industry, nor have they 

kept pace with process changes that 

have occurred over the last three 

decades. Existing steam electric power 

plants currently contribute 50–60 

percent of all toxic pollutants 

discharged to surface waters by all 

industrial categories regulated in the 

U.S. under the CWA. Furthermore, 

power plant discharges to surface waters 

are expected to increase as pollutants 

are increasingly captured by air 

pollution controls and transferred to 

wastewater discharges. The proposed 

regulation, which includes new 

requirements for both existing and new 

generating units, would reduce impacts 

to human health and the environment 

by reducing the amount of toxic metals 

and other pollutants currently 

discharged to surface waters from power 

plants. The EPA intends to take final 

action on the proposed rule by 

September 30, 2015. 

The EPA is endeavoring to enable 

EGUs to comply with applicable 

obligations under other power sector 

rules as efficiently as possible (e.g., by 

facilitating their ability to coordinate 

planning and investment decisions with 

respect to those rules) and, where 

possible, implement integrated 

compliance strategies. For example, in 

the proposed SE ELG rule, the EPA 

describes its thinking on how it might 

effectively harmonize the potential 

requirements of that rule with the 

requirements of the final CCR rule. 

Because these two rules affect similar 

units and may be met with similar 

compliance strategies, common-sense 

implementation timeframes were 

established in the CCR final rule so that 

utilities would not be required to make 

major decisions about CCR units 

without first understanding the 

implications that such decisions would 

have for meeting the surface water 

protection requirements of the final ELG 

rule. The EPA is taking into account 

these new CCR requirements for coal 

ash as it develops the final SE ELG rule. 

The EPA’s goal in harmonizing the SE 

ELG and CCR rules is to minimize the 

overall complexity of the two regulatory 

structures and avoid creating 

unnecessary burden. 

6. Other EPA Rules 

In addition to the power sector rules 

discussed above, the development of 

SIPs for criteria pollutants (ozone, 

PM2.5, and SO2) and regional haze may 

also have implications for existing 

fossil-fired EGUs. 

Regarding ozone, the proposal 

included a discussion of the June 6, 

2013, proposed implementation rule for 

the 2008 ozone National Ambient Air 

Quality Standards (NAAQS), addressing 

the statutory requirements for areas EPA 

has designated as nonattainment for the 

2008 ozone NAAQS. The final 

implementation rule for the 2008 ozone 

NAAQS was signed on February 13, 

2015, and published on March 6, 2015, 

with an effective date of April 6, 2015. 

In general, the 2008 ozone NAAQS 

implementation rule interprets 

applicable statutory requirements and 

provides flexibility to states to minimize 

administrative burdens associated with 

developing and implementing plans to 

meet and maintain the NAAQS. The 

rule establishes due dates for attainment 

plans and clarifies attainment dates for 

each ozone nonattainment area 

according to its classification based on 

air quality thresholds, with attainment 

dates starting in July 2015 through July 

2032 depending on an area’s 

classification. 

On November 25, 2014, the EPA 

Administrator signed the proposed 

rulemaking for the 2015 revisions to the 

ozone NAAQS. The proposal was 

published in the Federal Register on 

December 17, 2014 (79 FR 75234). The 

Administrator proposed to revise the 

primary ozone standard to a level in the 

range of 0.065 to 0.070 ppm and took 

comment on lower levels including 

0.060 ppm and on retaining the current 

standard of 0.075 ppm. Among other 

things, the ozone NAAQS proposal also 

proposed to retain the current indicator, 

averaging time, and form of the standard 

and included a proposed secondary 

ozone NAAQS in the 0.065 to 0.070 

ppm range. 

The proposal also outlined the key 

implementation milestones requiring 

revised SIPs, with due dates starting in 

October 2018 for infrastructure and 

interstate transport SIPs, attainment 

plans due 2020–21, and attainment 

dates of 2020–37. The EPA is under a 

court order to finalize its review of the 

ozone NAAQS by October 1, 2015. 

Some commenters expressed concern 

with the potential impact proposed 

revisions to the ozone NAAQS could 

have on state planning efforts and 

affected entities’ ability to comply with 

any potentially new requirements 

associated with a revised ozone NAAQS 

and those related to the 111(d) emission 

guidelines. In particular, commenters 

raised issues with a potentially more 

stringent ozone standard and the 

permitting and state planning 

implications this may create. While 

there was no discussion of the proposed 

revisions to the ozone NAAQS in the 

111(d) emission guidelines proposal, 

commenters expressed a desire for the 

EPA to coordinate promulgation of the 

final 111(d) emission guidelines (and 

any other climate regulations) with the 

potential revision to the ozone standard 

to provide certainty and flexibility for 

states and affected sources. 

While it is premature to speculate 

about the outcome of the ozone NAAQS 

review and how a more stringent ozone 

NAAQS may impact sources of ozone 

precursor emissions, including EGUs, 

we believe the planning and compliance 

timeframes that would follow from a 

revised ozone NAAQS and the 

timeframes we are finalizing today for 

submittal of the CAA section 111(d) 

state plans will allow considerable time 

for coordination by states in the 

development of their respective plans, 

as needed. As stated in 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 


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1035The 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/

201503Schedule.pdf. 

1036For 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. 

1037 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 

Continued 

the EPA was developing a proposed 

implementation rule to provide 

guidance to states on the development 

of SIPs for the 2012 PM2.5 NAAQS. The 

proposed PM2.5 SIP requirements rule 

was signed on March 10, 2015, and 

published on March 23, 2015 (80 FR 

15340). The proposal addresses a 

number of requirements including 

attainment plan due dates, attainment 

dates and attainment date extension 

criteria for Moderate and Serious 

nonattainment areas; determination 

criteria for Reasonably Available 

Control Measures (RACM) for Moderate 

areas and Best Available Control 

Measures (BACM) for Serious areas; 

plans for demonstrating reasonable 

further progress and for meeting 

periodic quantitative milestones; and 

criteria for reclassifying a Moderate 

nonattainment area to Serious. The EPA 

is planning to finalize the PM2.5

implementation rule in early 2016. 

There are currently only 9 areas 

designated nonattainment for the 2012 

PM2.5 NAAQS, with an effective date of 

April 15, 2015. Since the attainment 

plans for these areas must be completed 

and submitted to the EPA in September 

2016, we expect that the four states with 

such areas should have already decided 

on their approach to implementing the 

2012 PM2.5 NAAQS when they begin to 

develop their plans for implementing 

the 111(d) guidelines, and will be able 

to coordinate the two. 

Related to the SO2 NAAQS, and as 

stated in the proposal, the SO2 NAAQS 

was revised in June 2010 to protect 

public health from the short-term effects 

of SO2 exposure. In July 2013, the EPA 

designated 29 areas in 16 states as 

nonattainment for the SO2 NAAQS. The 

EPA based these nonattainment 

designations on the most recent set of 

certified air quality monitoring data as 

well as an assessment of nearby 

emission sources and weather patterns 

that contribute to the monitored levels. 

The date for attainment plans for these 

areas to be completed and submitted to 

the EPA was April 2015. As such, we 

expect states with such areas to have 

already decided on their approach to 

implementing the SO2 NAAQS as they 

start planning for implementation of the 

111(d) guidelines, which should allow 

for coordination and consideration of 

SO2 related air quality measures into 

their 111(d) planning. The EPA intends 

to address the designations for all other 

areas in three separate actions in the 

future.1035 These designations must be 

completed by no later than July 2, 2016, 

December 31, 2017, and December 31, 

2020 with attainment plans due 

between 2018 and 2022. 

Regarding requirements under the 

regional haze program, several affected 

EGUs have deadlines in the 2016–2021 

timeframe to install controls to comply 

with the Best Available Retrofit 

Technology (BART) and reasonable 

progress requirements of the Regional 

Haze Rule. Soon after these deadlines, 

some of the same affected EGUs may be 

required to reduce their utilization, 

convert into natural gas-fired facilities, 

or shut down entirely as a result of state 

111(d) plans. Some commenters have 

expressed concern that for these affected 

EGUs, specifically those that choose to 

retire, the capital equipment installed to 

comply with the Regional Haze Rule 

would likely become stranded assets. 

While the EPA is providing 

considerable flexibility for states and 

sources under the final 111(d) emission 

guidelines, the EPA acknowledges the 

possibility that some sources could 

ultimately be faced with the potential 

for stranded assets as a result of state 

111(d) plans. For these sources, 

however, states have the option of 

developing BART alternatives that 

replace control requirements that would 

otherwise result in stranded assets at a 

particular EGU with the aggregate 

emission reductions that will result 

from retirements, fuel switching, 

reduced utilization, or lesser controls at 

multiple EGUs. 

In fact, the EPA already has 

experience working with states to 

account for these very types of changed 

circumstances.1036 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 sourceby-source limitations reflecting the 

BSER performance rates to each affected 

EGU or to adopt rate-based or massbased emission performance goals, and 

to rely on a wide range of CO2 emission 

reduction measures, including measures 

that are not part of the BSER. The EPA 

is also providing states considerable 

flexibility with respect to the 

timeframes for plan development and 

implementation, with up to 3 years 

permitted for final plans to be submitted 

after the GHG emission guidelines are 

finalized, and up to 15 years for all 

emission reduction measures to be fully 

implemented. The EPA is establishing 

an 8-year interim period over which to 

achieve the full required reductions to 

meet the CO2 performance rates, and 

this begins in 2022, more than seven 

years from the June 18, 2014 date of 

proposal of the rulemaking. The 8-year 

interim period from 2022 through 2029, 

is separated into three steps, 2022–2024, 

2025–2027, and 2028–2029, each 

associated with its own interim CO2

emission performance rates. 

In light of these broad flexibilities, we 

believe that states will have ample 

opportunity, when developing and 

implementing their CAA section 111(d) 

plans, to coordinate their response to 

this requirement with source and state 

responses to any obligations that may be 

applicable to affected EGUs as a result 

of the MATS, CSAPR, 316(b), SE ELG 

and CCR rules, all of which are or soon 

will be final rules. In addition, we 

believe 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.1037 We also believe that the broad 


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appropriate, but will comply with all relevant legal 

requirements. 

1038The impacts presented in this section of the 

preamble represent an illustrative implementation 

of the guidelines. As states implement the final 

guidelines, they have sufficient flexibility to adopt 

different state-level or regional approaches that may 

yield different costs, benefits, and environmental 

impacts. For example, states may use the 

flexibilities described in these guidelines to find 

approaches that are more cost-effective for their 

particular state or choose approaches that shift the 

balance of co-benefits and impacts to match broader 

state priorities. 

1039 It is important to note that the differences 

between the analytical results for the rate-based and 

mass-based illustrative plan approaches presented 

in the RIA may not be indicative of likely 

differences between the approaches if implemented 

by states and affected EGUs in response to the final 

guidelines. If one approach performs differently 

than the other on a given metric during a given time 

period, this does not imply this will apply in all 

instances. 

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 This Action 1038

A. What are the air impacts? 

The EPA anticipates significant 

emission reductions under the final 

guidelines for the utility power sector. 

In the final emission guidelines, the 

EPA has translated the source categoryspecific CO2 emission performance rates 

into equivalent state-level rate-based 

and mass-based CO2 goals in order to 

maximize the range of choices that 

states will have in developing their 

plans. Because of the range of choices 

available to states and the lack of a 

priori knowledge about the specific 

choices states will make in response to 

the final goals, the Regulatory Impact 

Analysis (RIA) for this final action 

presents two scenarios designed to 

achieve these goals, which we term the 

‘‘rate-based’’ illustrative plan approach 

and the ‘‘mass-based’’ illustrative plan 

approach.1039

Under the rate-based approach, when 

compared to 2005, CO2 emissions are 

projected to be reduced by 

approximately 22 percent in 2020, 28 

percent in 2025, and 32 percent in 2030. 

Under the mass-based approach, when 

compared to 2005, CO2 emissions are 

projected to be reduced by 

approximately 23 percent in 2020, 29 

percent in 2025, and 32 percent in 2030. 

The final guidelines are projected to 

result in substantial co-benefits through 

reductions of SO2, NOX and PM2.5 that 

will have direct public health benefits 

by lowering ambient levels of these 

pollutants and ozone. Tables 15 and 16 

show expected CO2 and other air 

pollutant emissions in the base case and 

reductions under the final guidelines for 

2020, 2025, and 2030 for the rate-based 

and mass-based approaches, 

respectively. 

TABLE 15—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS FROM THE BASE CASE UNDER RATEBASED ILLUSTRATIVE PLAN APPROACH

CO2

(millions short tons) 

SO2

(thousand short tons) 

NOX

(thousand short tons) 

2020 Final Guidelines: 

Base Case ........................................................................................ 2,155 1,311 1,333 

Final Guidelines ................................................................................ 2,085 1,297 1,282 

Emissions Reductions ...................................................................... 69 14 50 

2025 Final Guidelines: 

Base Case ........................................................................................ 2,165 1,275 1,302 

Final Guidelines ................................................................................ 1,933 1,097 1,138 

Emissions Reductions ...................................................................... 232 178 165 

2030 Final Guidelines: 

Base Case ........................................................................................ 2,227 1,314 1,293 

Final Guidelines ................................................................................ 1,812 996 1,011 

Emissions Reductions ...................................................................... 415 318 282 

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

TABLE 16—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS FROM THE BASE CASE UNDER MASSBASED ILLUSTRATIVE PLAN APPROACH

CO2

(million short tons) 

SO2

(thousand short tons) 

NOX

(thousand short tons) 

2020 Final Guidelines: 

Base Case ........................................................................................ 2,155 1,311 1,333 

Final Guidelines ................................................................................ 2,073 1,257 1,272 

Emissions Reductions ...................................................................... 81 54 60 

2025 Final Guidelines: 

Base Case ........................................................................................ 2,165 1,275 1,302 

Final Guidelines ................................................................................ 1,901 1,090 1,100 

Emissions Reductions ...................................................................... 265 185 203 

2030 Final Guidelines: 

Base Case ........................................................................................ 2,227 1,314 1,293 

Final Guidelines ................................................................................ 1,814 1,034 1,015 

Emissions Reductions ...................................................................... 413 280 278 

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 


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1040See Endangered Species Consultation 

Handbook, U.S. Fish & Wildlife Service and 

National Marine Fisheries Service at 4–25 (March 

1998) (providing examples of direct effects: e.g., 

driving an off road vehicle through the nesting 

habitat of a listed species of bird and destroying a 

ground nest; building a housing unit and destroying 

the habitat of a listed species). Available at https:// 

www.fws.gov/ENDANGERED/esa-library/pdf/esa_

section7_handbook.pdf. 

1041See, 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). Available at 

http://www.doi.gov/solicitor/opinions/M-37017.pdf. 

1042See 75 FR at 25438 Table I.C 2–4 (May 7, 

2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012). 

1043EPA, Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate Average Fuel 

Economy Standards, Response to Comment 

Document for Joint Rulemaking at 4–102 (Docket ID 

EPA–OAR–HQ–2010–0799). Available at http://

www.epa.gov/otaq/climate/regulations/

420r10012a.pdf. 

The reductions in Tables 15 and 16 do 

not account for reductions in hazardous 

air pollutants (HAPs) that may occur as 

a result of this rule. For instance, the 

fine particulate reductions presented 

above do not reflect all of the reductions 

in many heavy metal particulates. 

B. Endangered Species Act 

As explained in the preamble to the 

proposed rule (79 FR at 34933–934), the 

EPA has carefully considered the 

requirements of section 7(a)(2) of the 

Endangered Species Act (ESA) and 

applicable ESA regulations, and 

reviewed relevant ESA case law and 

guidance, to determine whether 

consultation with the U.S. Fish and 

Wildlife Service (FWS) and/or National 

Marine Fisheries Service (together, the 

Services) is required by the ESA. The 

EPA proposed to conclude that the 

requirements of ESA section 7(a)(2) 

would not be triggered by promulgation 

of the rule, and we now finalize that 

determination. 

Section 7(a)(2) of the ESA requires 

federal agencies, in consultation with 

one or both of the Services (depending 

on the species at issue), to ensure that 

actions they authorize, fund, or carry 

out are not likely to jeopardize the 

continued existence of federally listed 

endangered or threatened species or 

result in the destruction or adverse 

modification of designated critical 

habitat of such species. 16 U.S.C. 

1536(a)(2). Under relevant 

implementing regulations, section 

7(a)(2) applies only to actions where 

there is discretionary federal 

involvement or control. 50 CFR 402.03. 

Further, under the regulations 

consultation is required only for actions 

that ‘‘may affect’’ listed species or 

designated critical habitat. 50 CFR 

402.14. Consultation is not required 

where the action has no effect on such 

species or habitat. Under this standard, 

it is the federal agency taking the action 

that evaluates the action and determines 

whether consultation is required. See 51 

FR 19926, 19949 (June 3, 1986). Effects 

of an action include both the direct and 

indirect effects that will be added to the 

environmental baseline. 50 CFR 402.02. 

Direct effects are the direct or 

immediate effects of an action on a 

listed species or its habitat.1040 Indirect 

effects are those that are ‘‘caused by the 

proposed action and are later in time, 

but still are reasonably certain to 

occur.’’ Id. To trigger the consultation 

requirement, there must thus be a causal 

connection between the federal action, 

the effect in question, and the listed 

species, and if the effect is indirect, it 

must be reasonably certain to occur. 

The EPA notes that the projected 

environmental effects of this rule are 

positive: Reductions in overall GHG 

emissions, and reductions in PM and 

ozone-precursor emissions (SO2 and 

NOX). The EPA recognizes that 

beneficial effects to listed species can, 

as a general matter, result in a ‘‘may 

affect’’ determination under the ESA. 

However, the EPA’s assessment that the 

rule will have an overall net positive 

environmental effect by virtue of 

reducing emissions of certain air 

pollutants does not address whether the 

rule may affect any listed species or 

designated critical habitat for ESA 

section 7(a)(2) purposes and does not 

constitute any finding of effects for that 

purpose. The fact that the rule will have 

overall positive effects on the national 

and global environment does not mean 

that the rule may affect any listed 

species in its habitat or the designated 

critical habitat of such species within 

the meaning of ESA section 7(a)(2) or 

the implementing regulations or require 

ESA consultation. The EPA has 

considered various types of potential 

effects in reaching the conclusion that 

ESA consultation is not required for this 

rule. 

With respect to the projected GHG 

emission reductions, the EPA 

considered in detail in the proposal why 

such reductions do not trigger ESA 

consultation requirements under section 

7(a)(2). As explained in the proposal, in 

reaching this conclusion the EPA was 

mindful of significant legal and 

technical analysis undertaken by FWS 

and the U.S. Department of the Interior 

(DOI) in the context of listing the polar 

bear as a threatened species under the 

ESA. In that context, in 2008, FWS and 

DOI expressed the view that the best 

scientific data available were 

insufficient to draw a causal connection 

between GHG emissions and effects on 

the species in its habitat.1041 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. 

As described in the proposal, the EPA 

has also previously considered issues 

relating to GHG emissions in connection 

with the requirements of ESA section 

7(a)(2) and has supplemented DOI’s 

analysis with additional consideration 

of GHG modeling tools and data 

regarding listed species. Although the 

GHG emission reductions projected for 

this final rule are large (estimated 

reductions of about 415 million short 

tons of CO2 in 2030 relative to the base 

case under the rate-based illustrative 

plan approach—see Table 14 above), the 

EPA evaluated larger reductions in 

assessing this same issue in the context 

of the light-duty vehicle GHG emission 

standards for model years 2012–2016 

and 2017–2025. There the agency 

projected emission reductions over the 

lifetimes of the model years in 

question 1042 which are roughly five to 

six times those projected above and, 

based on air quality modeling of 

potential environmental effects, 

concluded that ‘‘EPA knows of no 

modeling tool which can link these 

small, time-attenuated changes in global 

metrics to particular effects on listed 

species in particular areas. Extrapolating 

from global metric to local effect with 

such small numbers, and accounting for 

further links in a causative chain, 

remain beyond current modeling 

capabilities.’’ 1043 The EPA reached this 

conclusion after evaluating issues 

relating to potential improvements 

relevant to both temperature and 

oceanographic pH outputs. The EPA’s 

ultimate finding was that ‘‘any potential 

for a specific impact on listed species in 

their habitats associated with these very 

small changes in average global 

temperature and ocean pH is too remote 

to trigger the threshold for ESA section 

7(a)(2).’’ Id. The EPA believes that the 

same conclusion applies to the present 

rule. See, e.g., Ground Zero Center for 

Non-Violent Action v. U.S. Dept. of 

Navy, 383 F. 3d 1082, 1091–92 (9th Cir. 

2004) (where the likelihood of jeopardy 

to a species from a federal action is 

extremely remote, ESA does not require 

consultation). The EPA’s conclusion is 

entirely consistent with DOI’s analysis 

regarding ESA requirements in the 


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1044The EPA has received correspondence from 

a U.S. Senator and a Member of the U.S. House of 

Representatives noting that the Services have 

identified several listed species affected by global 

climate change. See Letter from Rob Bishop, 

Chairman, House Committee on Natural Resources, 

to Gina McCarthy, Administrator, U.S. 

Environmental Protection Agency, dated June 11, 

2015; Letter from Rob Bishop, Chairman, House 

Committee on Natural Resources, and James M. 

Inhofe, Chairman, Senate Committee on 

Environment and Public Works, to Gina McCarthy, 

Administrator, U.S. Environmental Protection 

Agency, dated June 15, 2015. EPA’s assessment of 

ESA requirements in connection with the present 

rule does not address whether global climate 

change may, as a general matter, be a relevant 

consideration in the status of certain listed species. 

Rather, the requirements of ESA section 7(a)(2) 

must be considered and applied to the specific 

action at issue. As explained above, EPA’s 

conclusion that ESA section 7(a)(2) consultation is 

not required here is premised on the specific facts 

and circumstances of the present rule and is fully 

consistent with prior relevant analyses conducted 

by DOI, FWS, and EPA. 

1045One commenter questioned the EPA’s 

citation to American Trucking Assn’s. As stated by 

the commenter, the statute at issue in that case— 

the Regulatory Flexibility Act (RFA)—is 

distinguishable from the ESA in that it addresses 

only direct effects and does not consider indirect 

effects. The commenter misreads the EPA’s citation 

to this case. The EPA cites this case simply to 

reference a decision considering the impacts of an 

EPA action—the revision of a NAAQS under the 

CAA—that in certain respects provides a useful 

analogy to the present rule. A NAAQS is 

implemented through a series of subsequent 

planning decisions generally taken by states by 

means of adoption of SIPs. States can choose to 

impose or avoid the types of impacts at issue in the 

D.C. Circuit case through their planning decisions; 

thus such impacts were not viewed as having been 

caused—for purposes of the RFA—by the EPA’s 

promulgation of the revised NAAQS in the first 

instance. The standard setting and implementation 

mechanisms under section 111(d) are very similar. 

Under section 111(d), the EPA is required to 

establish ‘‘a procedure similar to that provided by 

section 7410’’—the provision establishing the SIP 

mechanism for implementing NAAQS. Thus, the 

D.C. Circuit’s discussion provides a useful analogy 

to the present rule and the various types of 

potential effects that may be attributable to future 

implementation planning decisions by states and 

other entities as they exercise their discretion in 

determining how to implement the federal 

guidelines, but not to promulgation of the rule 

itself. The EPA’s citation to this case was not 

intended to address any comparison of the scope of 

effects covered by the RFA and the effects 

cognizable under section 7(a)(2) of the ESA. The 

EPA is aware that the ESA addresses both direct 

and indirect effects as defined by the applicable 

ESA regulations. The discussion supporting the 

EPA’s ESA conclusion expressly acknowledges the 

relevance of indirect effects to the ESA analysis and 

explains why such effects are not present here. 

1046A congressional letter of June 11, 2015, 

referenced above asserts that EPA’s modeling 

suggests that the Big Bend Power Station and 

Crystal River Energy Complex in Florida will be 

prematurely retired as a result of the rule. EPA 

notes that any such facility-level projections 

associated with the rule cannot be stated with 

sufficient certainty to qualify as potential indirect 

effects under the ESA. These projections are based 

on numerous assumptions regarding a variety of 

planning and business decisions yet to be made by 

the implementing governments (usually states) and 

facility owners. Given the wide degrees of 

discretion and flexibility and the numerous options 

available for such decision making, the potential for 

such outcomes to be realized as currently projected 

is at this point too uncertain to qualify as an effect 

under the ESA. 

context of federal actions involving 

GHG emissions.1044

With regard to non-GHG air 

emissions, the EPA also projects 

substantial reductions of SO2 and NOX

as a collateral consequence of this final 

action. However, CAA section 111(d)(1) 

standards cannot directly control 

emissions of criteria pollutants. See 

CAA section 111(d)(1)(i). Consequently, 

CAA section 111(d) provides no 

discretion to adjust the standard based 

on potential impacts to endangered 

species of reduced criteria pollutant 

emissions. Section 7(a)(2) consultation 

thus is not required with respect to the 

projected reductions of criteria pollutant 

emissions. See 50 CFR 402.03; see also, 

WildEarth Guardians v. U.S. Envt’l 

Protection Agency, 759 F.3d 1196, 

1207–10 (10th Cir. 2014) (EPA has no 

duty to consult under section 7(a)(2) of 

the ESA regarding hazardous air 

pollutant controls that it did not 

require—and likely lacked authority to 

require—in a federal implementation 

plan for regional haze controls under 

section 169A of the CAA). 

Finally, the EPA has also considered 

other potential effects of the rule 

(beyond reductions in air pollutants) 

and whether any such effects are 

‘‘caused by’’ the rule and ‘‘reasonably 

certain to occur’’ within the meaning of 

the ESA regulatory definition of the 

effects of an action. 50 CFR 402.02. As 

the EPA noted in the proposal, there are 

substantial questions as to whether any 

potential for relevant effects results from 

any element of the rule or would result 

instead from separate decisions and 

actions made in connection with the 

development, implementation, and 

enforcement of a plan to implement the 

standards established in the rule. Cf. 

American Trucking Assn’s v. EPA, 175 

F. 3d 1027, 1043–45 (D.C. Cir. 1999), 

rev’d on different grounds sub nom., 

Whitman v. American Trucking Assn’s, 

531 U.S. 457 (2000) (National Ambient 

Air Quality Standards have no 

economic impact, for purposes of 

Regulatory Flexibility Act, because 

impacts result from the actions of states 

through their development, 

implementation and enforcement of 

SIPs).1045 The EPA recognized, for 

instance, that questions may exist 

whether decisions such as increased 

utilization of solar or wind power could 

have effects on listed species. The EPA 

received comments on the proposal 

asserting that because potential 

increased reliance on wind or solar 

power may be an element of building 

block 3, and because wind and solar 

facilities may in some cases have effects 

on listed species, the EPA must consult 

under the ESA on this aspect of the rule. 

The EPA is also aware of certain 

questions regarding potential effects of 

the rule on the Big Bend Power Station 

located in Florida, which discharges 

effluent that provides a warm water 

refuge for manatees. The Big Bend 

Power Station and another coal-fired 

facility located in Florida—the Crystal 

River Plant—are, for example, 

referenced in the June 11, 2015, and 

June 15, 2015, congressional letters to 

EPA cited above. 

The EPA has carefully considered the 

comments and the correspondence from 

Congress as well as the case law and 

other materials cited in those 

documents. The EPA does not believe 

that the effects of potential future 

changes in the energy sector—including 

increased reliance on wind or solar 

power as a result of future potential 

actions by states or other implementing 

entities—or any potential alterations in 

the operations of any particular facility 

are caused by the current rule or 

sufficiently certain to occur so as to 

require ESA consultation on the rule. 

The EPA appreciates that the ESA 

regulations call for consultation where 

actions authorized, funded, or carried 

out by federal agencies may have 

indirect effects on listed species or 

designated critical habitat. However, as 

noted above, indirect effects must be 

caused by the action at issue and must 

be reasonably certain to occur. At this 

point, there is no reasonable certainty 

regarding implementation of any 

planning measures in any location, let 

alone in any location occupied by a 

listed species or its designated critical 

habitat. The EPA cannot predict with 

reasonable certainty where such 

measures may take effect or which 

measures may be adopted. It is not clear, 

for instance, whether a particular 

implementation plan will call, if at all, 

for increased reliance 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.1046 The precise steps included 

in an implementation plan cannot be 

determined or ordered by this federal 

action, and they are not sufficiently 

certain to be attributable to this final 

rule for ESA purposes. These steps will 

flow from a series of later in time 

decisions generally made by other 

entities—usually states—in their 


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1047See 51 FR at 19933 (describing effects that are 

‘‘reasonably certain to occur’’ in the context of 

consideration of cumulative effects and 

distinguishing broader consideration that may be 

appropriate in applying a procedural statute such 

as the National Environmental Policy Act, as 

opposed to a substantive provision such as ESA 

section 7(a)(2) that may prohibit certain federal 

actions); Endangered Species Consultation 

Handbook, U.S. Fish & Wildlife Service and 

National Marine Fisheries Service at 4–30 (March 

1998) (in the same context, describing indicators 

that an activity is reasonably certain to occur as 

including governmental approvals of the action or 

indications that such approval is imminent, project 

sponsors’ assurance that the action will proceed, 

obligation of venture capital, or initiation of 

contracts; and noting that the more governmental 

administrative discretion remains to be exercised, 

the less there is reasonable certainty the action will 

proceed). Available at https://www.fws.gov/

ENDANGERED/esa-library/pdf/esa_section7_

handbook.pdf. 

1048EPA also notes that some of the future 

implementing activities may involve federal actions 

that are subject to ESA consultation, thus providing 

consideration of any impacts on listed species at the 

appropriate point when particular activities have 

become reasonably certain. Several commenters on 

the proposal specifically noted that such future 

activities—e.g., development of additional RE 

facilities such as wind farms—may call for ESA 

consultation. Further, EPA notes that section 9 of 

the ESA, which prohibits the take of individuals of 

most listed species, provides an additional 

protection for listed species as future implementing 

activities become reasonably certain. 

1049The commenters cite certain cases that they 

assert support consulting under ESA section 7(a)(2). 

The EPA has considered these cases, each of which 

is distinguishable from the present rule. By way of 

example, a commenter cites two cases involving 

EPA actions: Defenders of Wildlife v. EPA, 420 F.3d 

946 (9th Cir. 2005), rev’d, National Association of 

Homebuilders v. Defenders of Wildlife, 551 U.S. 644 

(2007); and Washington Toxics Coalition v. EPA, 

413 F.3d 1024 (9th Cir. 2005). In Defenders of 

Wildlife (a decision that was reversed by the U.S. 

Supreme Court), a principal relevant impact of the 

federal action at issue—the EPA’s approval of a 

state’s permitting program under the Clean Water 

Act—was that following the action, the relevant 

permitted activities would no longer be subject to 

consultation under the ESA. By contrast, 

promulgation of the present rule will result in no 

change to any ESA requirements applicable to any 

future activities directed by plans (either state or 

federal) implementing the rule. The action at issue 

in Washington Toxics Coalition involved the EPA’s 

registration of certain pesticide active ingredients 

under the Federal Insecticide, Fungicide, and 

Rodenticide Act. Such actions provide 

authorization for the sale and distribution of those 

products, consistent with applicable labelling 

requirements. The EPA also notes that under the 

EPA’s regulations, registered pesticide labels must, 

among other things, specify the product ingredients 

and the methods and sites of product application. 

40 CFR 156.10. By contrast, the present rule only 

sets goals and describes potential pathways to 

meeting those goals, all of which are subject to 

future considerations and decisions involved in the 

implementation of plans (generally by states). The 

rule neither authorizes, nor directs, any of the 

future measures to meet the rule’s goals. Those 

activities remain subject to the full range of future 

decision making addressing which types of 

measures to implement, what emitting entities will 

be affected, how much, and when. 

distinct planning processes. These later 

decisions cannot now be required by the 

rule, are not caused by the rule, and are 

not reasonably certain to occur. The 

EPA also notes that the plans adopted 

for particular states may themselves 

provide wide degrees of implementation 

flexibility, thus further increasing the 

uncertainty that any species-impacting 

activity will occur in any particular 

location, if at all. The Services have 

explained that section 7(a)(2) was not 

intended to preclude federal actions 

based on potential future speculative 

effects.1047 These are precisely the types 

of speculative future activities and 

effects at issue here.1048 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.1049

C. What are the energy impacts? 

The final guidelines have important 

energy market implications. Table 17 

presents a variety of important energy 

market impacts for 2020, 2025, and 2030 

under both the rate-based and massbased illustrative plan approaches. 

TABLE 17—SUMMARY TABLE OF IMPORTANT ENERGY MARKET IMPACTS FOR RATE-BASED AND MASS-BASED

ILLUSTRATIVE PLAN APPROACHES

[Percent change from base case] 

Rate-based Mass-based 

2020 2025 2030 2020 2025 2030 

Retail electricity prices ..................................................... 3 1 1 3 2 0 

Price of coal at minemouth .............................................. ¥1 ¥5 ¥4 ¥1 ¥5 ¥3 

Coal production for power sector use ............................. ¥5 ¥14 ¥25 ¥7 ¥17 ¥24 

Price of natural gas delivered to power sector ................ 5 ¥8 2 4 ¥3 ¥2 

Natural gas use for electricity generation ........................ 3 ¥1 ¥1 5 0 ¥4 

These figures reflect the EPA’s 

illustrative modeling that presumes 

policies that lead to generation shifts 

and growing use of demand-side EE and 

renewable electricity generation out to 

2029. If states make different policy 

choices, impacts could be different. For 

instance, if states implement renewable 

and/or demand-side EE policies on a 

more aggressive time-frame, impacts on 

natural gas and electricity prices would 

likely be less. Implementation of other 

measures not included in the BSER 

calculation or compliance modeling, 

such as nuclear uprates, transmission 

system improvements, use of energy 

storage technologies or retrofit CCS, 

could also mitigate gas price and/or 

electricity price impacts. 

Energy market impacts from the 

guidelines are discussed more 

extensively in the RIA found in the 

docket for this rulemaking. 

D. What are the compliance costs? 

The compliance costs of this final 

action are represented in this analysis as 

the change in electric power generation 

costs between the base case and the 

final rule in which states pursue a 

distinct set of strategies beyond the 

strategies taken in the base case to meet 

the terms of the final guidelines. The 

compliance costs estimates include cost 

estimates for demand-side EE. The 

compliance assumptions—and, 

therefore, the projected compliance 

costs—set forth in this analysis are 

illustrative in nature and do not 

represent the full suite of compliance 

flexibilities states may ultimately 

pursue. The illustrative analysis is 

designed to reflect, to the extent 

possible, the scope and the nature of the 

final guidelines. However, there is 

considerable uncertainty with regards to 

the precise measures that states will 

adopt to meet the final requirements, 

because there are considerable 

flexibilities afforded to the states in 

developing their state plans. 

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 demand-side EE 

programs, and other actions associated 

with compliance. These important 


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1050The MR&R costs estimates are $65 million in 

2020, $15 million in 2025 and $15 million in 2030 

and are assumed to be the same for both rate-based 

and mass-based illustrative plan approaches. 

dynamics are discussed in more detail 

in the RIA in the rulemaking docket. 

The EPA estimates the annual 

incremental compliance cost for the 

rate-based approach for final emission 

guidelines to be $2.5 billion in 2020, 

$1.0 billion in 2025 and $8.4 billion in 

2030, including the costs associated 

with monitoring, reporting, and 

recordkeeping (MR&R).1050 The EPA 

estimates the annual incremental 

compliance cost for the mass-based 

approach for final emission guidelines 

to be $1.4 billion in 2020, $3.0 billion 

in 2025 and $5.1 billion in 2030, 

including the costs associated with 

MR&R. 

More detailed cost estimates are 

available in the RIA included in the 

rulemaking docket. 

E. What are the economic and 

employment impacts? 

The final standards are projected to 

result in certain changes to power 

system operation as a compliance with 

the standards. See Table 16 above for a 

variety of important energy market 

impacts for 2020, 2025, and 2030 under 

both the rate-based and mass-based 

illustrative plan approaches. 

It is important to note that the EPA’s 

modeling does not necessarily account 

for all of the factors that may influence 

business decisions regarding future 

coal-fired capacity. Many power 

companies already factor a potential 

financial liability associated with 

carbon emissions into their long term 

capacity planning that would further 

influence business decisions to replace 

these aging assets with modern, and 

significantly cleaner, generation. 

The compliance modeling done to 

support the final rule assumes that 

overall electric demand will decrease as 

states ramp up programs that result in 

lower overall demand. Demand-side EE 

levels are expected to increase such that 

they achieve about a 7.8 percent 

reduction on overall electricity demand 

levels in 2030 under the final 

guidelines. 

Changes in price or demand for 

electricity, natural gas, and coal can 

impact markets for goods and services 

produced by sectors that use these 

energy inputs in the production process 

or supply those sectors. Changes in the 

cost of production may result in changes 

in prices, quantities produced, and 

profitability of affected firms. The EPA 

recognizes that these guidelines provide 

significant flexibilities and states 

implementing the guidelines may 

choose to mitigate impacts to some 

markets outside the utility power sector. 

Similarly, demand for new generation or 

demand-side EE as a result of states 

implementing the guidelines can result 

in shifts in production and profitability 

for firms that supply those goods and 

services. 

Executive Order 13563 directs federal 

agencies to consider the effect of 

regulations on job creation and 

employment. According to the 

Executive Order, ‘‘our regulatory system 

must protect public health, welfare, 

safety, and our environment while 

promoting economic growth, 

innovation, competitiveness, and job 

creation. It must be based on the best 

available science.’’ (Executive Order 

13563, 2011) Although standard benefitcost analyses have not typically 

included a separate analysis of 

regulation-induced employment 

impacts, we typically conduct 

employment analyses. While the 

economy continues moving toward fullemployment, employment impacts are 

of particular concern and questions may 

arise about their existence and 

magnitude. 

States have the responsibility and 

flexibility to implement policies and 

practices for compliance with the final 

guidelines. Quantifying the associated 

employment impacts is complicated by 

the wide range of approaches that states 

may use. As such, the EPA’s 

employment analysis includes projected 

employment impacts associated with 

illustrative plan approaches for these 

guidelines for the electric power 

industry, coal and natural gas 

production, and demand-side EE 

activities. These projections are derived, 

in part, from a detailed model of the 

utility power sector used for this 

regulatory analysis, and U.S government 

data on employment and labor 

productivity. In the electricity, coal, and 

natural gas sectors, the EPA estimates 

that these guidelines could result in a 

net decrease of approximately 25,000 

job-years in 2025 for the final guidelines 

under the rate-based illustrative plan 

approach and approximately 26,000 jobyears in 2025 under the mass-based 

approach. For 2030, the estimates of the 

net decrease in job-years are 31,000 

under the rate-based approach and 

34,000 under the mass-based approach. 

The agency is also offering an 

illustrative calculation of potential 

employment effects due to demand-side 

EE programs. Employment impacts from 

demand-side energy EE programs in 

2030 could range from approximately 

52,000 to 83,000 jobs under the final 

guidelines. 

By its nature, demand-side EE reduces 

overall demand for electric power. The 

EPA recognizes as more efficiency is 

built into the U.S. power system over 

time, lower fuel requirements may lead 

to fewer jobs in the coal and natural gas 

extraction sectors, as well as in fossilfuel fired EGU construction and 

operation than would otherwise have 

been expected. The EPA also recognizes 

the fact that, in many cases, 

employment gains and losses that might 

be attributable to this rule would be 

expected to affect different sets of 

people. Moreover, workers who lose 

jobs in these sectors may find 

employment elsewhere just as workers 

employed in new jobs in these sectors 

may have been previously employed 

elsewhere. Therefore, the employment 

estimates reported in these sectors may 

include workers previously employed 

elsewhere. This analysis also does not 

capture potential economy-wide 

impacts due to changes in prices (of 

fuel, electricity, labor, for example) or 

other factors such as improved labor 

productivity and reduced health care 

expenditures resulting from cleaner air. 

For these reasons, the numbers reported 

here should not be interpreted as a net 

national employment impact. 

F. What are the benefits of the final 

goals? 

Implementing the final standards will 

generate benefits by reducing emissions 

of CO2 and criteria pollutant precursors, 

including SO2, NOX, and directlyemitted 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 co-benefits for the 

rate-based approach to be $3.5 to $4.6 

billion in 2020, $18 to $28 billion in 

2025, and $34 to $54 billion in 2030 (3 

percent discount rate, 2011$). Total 

combined climate benefits and health 

co-benefits for the mass-based approach 

are estimated to be $5.3 to $8.1 billion 

in 2020, $19 to $29 billion in 2025, and 


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$32 to $48 billion in 2030 (3 percent 

discount rate, 2011$). A summary of the 

emission reductions and monetized 

benefits estimated for this rule at all 

discount rates is provided in Tables 15 

through 22 of this preamble. 

TABLE 18—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE FINAL GUIDELINES

[Billions of 2011$] a

Year Discount rate 

(statistic) 

Monetized climate benefits 

2020 2025 2030 

Rate-based Approach 

CO2 Reductions (million short tons) ............... ......................................................................... 69 232 415 

5 percent (average SC-CO2) ......................... $0.80 $3.1 $6.4 

3 percent (average SC-CO2) ......................... $2.8 $10 $20 

2.5 percent (average SC-CO2) ...................... $4.1 $15 $29 

3 percent (95th percentile SC-CO2) ............... $8.2 $31 $61 

Mass-based Approach 

CO2 Reductions (million short tons) ............... ......................................................................... 81 265 413 

5 percent (average SC-CO2) ......................... $0.94 $3.6 $6.4 

3 percent (average SC-CO2) ......................... $3.3 $12 $20 

2.5 percent (average SC-CO2) ...................... $4.9 $17 $29 

3 percent (95th percentile SC-CO2) ............... $9.7 $35 $60 

a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account for 

changes in non-CO2 GHG emissions. These estimates are based on the global social cost of carbon (SC-CO2) estimates for the analysis years 

and are rounded to two significant figures. 

TABLE 19—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE FINAL GUIDELINES, RATE-BASED

APPROACH

[Billions of 2011$] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized 

health 

co-benefits 

(3 percent 

discount) 

Monetized 

Health 

Co-benefits 

(7 percent 

discount) 

Final Guidelines, Rate-based Approach, 2020 

PM2.5 precursors: b

SO2 ................................................................................................................................. 14 $0.44 to $0.99 .. $0.39 to $0.89 

NOX ................................................................................................................................ 50 $0.14 to $0.33 .. $0.13 to $0.30 

Ozone precursor: c

NOX (ozone season only) .............................................................................................. 19 $0.12 to $0.52 .. $0.12 to $0.52 

Total Monetized Health Co-benefits ........................................................................ ........................ $0.70 to $1.8 .... $0.64 to $1.7 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ........................ $3.5 to $4.6 ...... $3.5 to $4.5 

Final Guidelines, Rate-based Approach, 2025 

PM2.5 precursors: b

SO2 ................................................................................................................................. 178 $6.4 to $14 ....... $5.7 to $13 

NOX ................................................................................................................................ 165 $0.56 to $1.3 .... $0.50 to $1.1 

Ozone precursor: c

NOX (ozone season only) .............................................................................................. 70 $0.49 to $2.1 .... $0.49 to $2.1 

Total Monetized Health Co-benefits ........................................................................ $7.4 to $18 ....... $6.7 to $16 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d $18 to $28 ........ $17 to $26 

Final Guidelines, Rate-based Approach, 2030 

PM2.5 precursors: b

SO2 ................................................................................................................................. 318 $12 to $28 ........ $11 to $25 

NOX ................................................................................................................................ 282 $1.0 to $2.3 ...... $0.93 to $2.1 

Ozone precursor: c

NOX (ozone season only) .............................................................................................. 118 $0.86 to $3.7 .... $0.86 to $3.7 

Total Monetized Health Co-benefits ........................................................................ $14 to $34 ........ $13 to $31 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits. d $34 to $54 ........ $33 to $51 

aAll 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. 


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bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors, such as SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits 

would increase overall benefits by a few percent based on the analyses conducted for the proposed rule. PM co-benefits are shown as a range 

reflecting the use of two concentration-response functions, with the lower end of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. cThe 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 

co-benefits occur in the analysis year, so they are the same for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent). Referred to as the social cost of carbon, each value increases over time. For the purposes 

of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and 

value of considering the full range of social cost of carbon values. We provide combined climate and health estimates based on additional discount rates in the RIA. 

TABLE 20—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE FINAL GUIDELINES, MASS-BASED

APPROACH

[Billions of 2011$] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized 

health 

co-benefits 

(3 percent 

discount) 

Monetized 

health 

co-benefits 

(7 percent 

discount) 

Final Guidelines, Mass-based Approach, 2020 

PM2.5 precursors: b

SO2 ....................................................................................................................................... 54 $1.7 to $3.8 $1.5 to $3.4 

NOX ...................................................................................................................................... 60 $0.17 to $0.39 $0.16 to $0.36 

Ozone precursor: c

NOX (ozone season only) .................................................................................................... 23 $0.14 to $0.61 $0.14 to $0.61 

Total Monetized Health Co-benefits .............................................................................. ........................ $2.0 to $4.8 $1.8 to $4.4 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ...... ........................ $5.3 to $8.1 $5.1 to $7.7 

Final Guidelines, Mass-based Approach, 2025 

PM2.5 precursors: b

SO2 ....................................................................................................................................... 185 $6.0 to $13 $5.4 to $12 

NOX ...................................................................................................................................... 203 $0.58 to $1.3 $0.52 to $1.2 

Ozone precursor: c

NOX (ozone season only) .................................................................................................... 88 $0.56 to $2.4 $0.56 to $2.4 

Total Monetized Health Co-benefits .............................................................................. ........................ $7.1 to $17 $6.5 to $16 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ...... ........................ $19 to $29 $18 to $27 

Final Guidelines, Mass-based Approach, 2030 

PM2.5 precursors: b

SO2 ....................................................................................................................................... 280 $10 to $23 $9.0 to $20 

NOX ...................................................................................................................................... 278 $0.87 to $2.0 $0.79 to $1.8 

Ozone precursor: c

NOX (ozone season only) ............................................................................................................ 121 $0.82 to $3.5 $0.82 to $3.5 

Total Monetized Health Co-benefits .............................................................................. ........................ $12 to $28 $11 to $26 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ...... ........................ $32 to $48 $31 to $46 

aAll 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. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors, such as SO2 and NOX. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits 

would increase overall benefits by a few percent based on the analyses conducted for the proposed rule. PM co-benefits are shown as a range 

reflecting the use of two concentration-response functions, with the lower end of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. cThe 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 

co-benefits occur in the analysis year, so they are the same for all discount rates. dWe 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. 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64931 

1051 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 the Treasury (May 2013, 

Revised July 2015). Available at: http://

www.whitehouse.gov/sites/default/files/omb/

inforeg/scc-tsd-final-july-2015.pdf. 

1052 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/for-agencies/Social-Cost-of-Carbon-forRIA.pdf. 

1053The current version of the TSD is available 

at: https://www.whitehouse.gov/sites/default/files/

omb/inforeg/scc-response-to-comments-final-july2015.pdf, Docket ID EPA–HQ–OAR–2013–0495, 

Technical Support Document: Technical Update of 

the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866, Interagency 

Working Group on Social Cost of Carbon, with 

participation by Council of Economic Advisers, 

Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, Domestic 

Policy Council, Environmental Protection Agency, 

National Economic Council, Office of Management 

and Budget, Office of Science and Technology 

Policy, and Department of Treasury (May 2013, 

Revised July 2015). 

1054See https://www.whitehouse.gov/omb/oira/

social-cost-of-carbon for additional details, 

including the OMB Response to Comments and the 

SC-CO2 TSDs. 

1055The current version of the TSD is available 

at: https://www.whitehouse.gov/sites/default/files/

omb/inforeg/scc-tsd-final-july-2015.pdf. The 2010 

and 2013 TSDs present SC-CO2 in 2007$ per metric 

ton. The estimates were adjusted to (1) short tons 

for using conversion factor 0.90718474 and (2) 

2011$ using GDP Implicit Price Deflator, http://

www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/

ECONI-2013-02-Pg3.pdf. 

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.1051 We refer to these 

estimates, which were developed by the 

U.S. Government, as ‘‘SC-CO2

estimates.’’ The SC-CO2 is a metric that 

estimates the monetary value of impacts 

associated with marginal changes in 

CO2 emissions in a given year. It 

includes a wide range of anticipated 

climate impacts, such as net changes in 

agricultural productivity and human 

health, property damage from increased 

flood risk, and changes in energy system 

costs, such as reduced costs for heating 

and increased costs for air conditioning. 

It is typically used to assess the avoided 

damages as a result of regulatory actions 

(i.e., benefits of rulemakings that lead to 

an incremental reduction in cumulative 

global CO2 emissions). 

The SC-CO2 estimates used in this 

analysis were developed over many 

years, using the best science available, 

and with input from the public. 

Specifically, an interagency working 

group (IWG) that included the EPA and 

other executive branch agencies and 

offices used three integrated assessment 

models (IAMs) to develop the SC-CO2

estimates and recommended four global 

values for use in regulatory analyses. 

The SC-CO2 estimates were first 

released in February 2010 and updated 

in 2013 using new versions of each 

IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD) 1052

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).1053

The EPA received numerous 

comments on the SC-CO2 estimates as 

part of this rulemaking. The comments 

covered a wide range of topics including 

the technical details of the modeling 

conducted to develop the SC-CO2

estimates, the aggregation and 

presentation of the SC-CO2 estimates, 

and the process by which the SC-CO2

estimates were derived. Many but not 

all commenters were supportive of the 

SC-CO2 and its application to this 

rulemaking. Commenters also provided 

constructive recommendations for 

potential opportunities to improve the 

SC-CO2 estimates in future updates. 

Many of these comments were similar to 

those that OMB’s Office of Information 

and Regulatory Affairs received in 

response to a separate request for public 

comment on the approach used to 

develop the estimates. After careful 

evaluation of the full range of comments 

submitted to OMB, the IWG continues 

to recommend the use of the SC-CO2

estimates in regulatory impact 

analysis.1054 With the release of the 

response to comments, the IWG 

announced plans to obtain expert 

independent advice from the National 

Academies of Sciences, Engineering, 

and Medicine (Academies) to ensure 

that the SC-CO2 estimates continue to 

reflect the best available scientific and 

economic information on climate 

change. The Academies review will be 

informed by the public comments 

received and focus on the technical 

merits and challenges of potential 

approaches to improving the SC-CO2

estimates in future updates. See the EPA 

Response to Comments document for 

the complete response to comments 

received on SC-CO2 as part of this 

rulemaking. 

Concurrent with OMB’s publication of 

the response to comments on SC-CO2

and announcement of the Academies 

process, OMB posted a revised TSD that 

includes two minor technical 

corrections to the current estimates. One 

technical correction addressed an 

inadvertent omission of climate change 

damages in the last year of analysis 

(2300) in one model and the second 

addressed a minor indexing error in 

another model. On average the revised 

SC-CO2 estimates are one dollar less 

than the mean SC-CO2 estimates 

reported in the November 2013 revision 

to the May 2013 TSD. The change in the 

estimates associated with the 95th 

percentile estimates when using a 3 

percent discount rate is slightly larger, 

as those estimates are heavily 

influenced by the results from the 

model that was affected by the indexing 

error. 

The EPA, as a member of the IWG on 

the SC-CO2, has carefully examined and 

evaluated the minor technical 

corrections in the revised TSD and the 

public comments submitted to OMB’s 

separate SC-CO2 comment process. 

Additionally, the EPA has carefully 

examined and evaluated all comments 

received regarding the SC-CO2 through 

this rulemaking process. The EPA 

concurs with the IWG’s conclusion that 

it is reasonable, and scientifically 

appropriate, to use the current SC-CO2

estimates for purposes of regulatory 

impact analysis, including for this 

proceeding. 

The four SC-CO2 estimates are as 

follows: $12, $40, $60, and $120 per 

short ton of CO2 emissions in the year 

2020 (2011$).1055 The first three values 

are based on the average SC-CO2 from 

the three IAMs, at discount rates of 5, 

3, and 2.5 percent, respectively. The SCCO2 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 


tkelley on DSK3SPTVN1PROD with BOOK 2
64932 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1056http://www.epa.gov/airquality/benmap/

index.html. 

1057U.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>. 

1058U.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>. 

1059U.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>. 

1060U.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_

Apportionment_BPT_TSD_1_31_13.pdf>. 

1061 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. Available at http://www.healtheffects.org/ 

Pubs/RR140-Krewski.pdf. 

1062Lepeule, 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. 

1063Roman, 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. 

1064Bell, M.L., et al. 2004. ‘‘Ozone and ShortTerm Mortality in 95 U.S. Urban Communities, 

1987–2000.’’ Journal of the American Medical 

Association, 292(19), pp. 2372–8. 

1065Levy, 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. 

rate. It is included to represent higherthan-expected impacts from temperature 

change further out in the tails of the SCCO2 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 noncatastrophic impacts, their incomplete 

treatment of adaptation and 

technological change, uncertainty in the 

extrapolation of damages to high 

temperatures, and assumptions 

regarding risk aversion. Currently, IAMs 

do not assign value to all of the 

important impacts of CO2 recognized in 

the literature, such as ocean 

acidification or potential tipping points, 

for various reasons, including the 

inherent difficulties in valuing nonmarket impacts and the fact that the 

science incorporated into these models 

understandably lags behind the most 

recent research. Nonetheless, these 

estimates and the discussion of their 

limitations represent the best available 

information about the social benefits of 

CO2 emission reductions to inform the 

benefit-cost analysis. As previously 

noted, the IWG plans to seek 

independent expert advice on technical 

opportunities to improve the SC-CO2

estimates from the Academies. The 

Academies process will help to ensure 

that the SC-CO2 estimates used by the 

federal government continue to reflect 

the best available science and 

methodologies. Additional details are 

provided in the TSDs. 

The health co-benefits estimates 

represent the total monetized human 

health benefits for populations exposed 

to reduced PM2.5 and ozone resulting 

from emission reductions from the 

illustrative compliance strategy for the 

final standards. Unlike the global SCCO2 estimates, the air pollution health 

co-benefits are estimated for the 

contiguous U.S. only. We used a 

‘‘benefit-per-ton’’ approach to estimate 

the benefits of this rulemaking. To 

create the PM2.5 benefit-per-ton 

estimates, we conducted air quality 

modeling for an illustrative scenario 

reflecting the proposed standards to 

convert precursor emissions into 

changes in ambient PM2.5 and ozone 

concentrations. We then used these air 

quality modeling results in BenMAP 1056

to calculate average regional benefit-perton estimates using the health impact 

assumptions used in the PM NAAQS 

RIA 1057 and Ozone NAAQS 

RIAs.1058 1059 The three regions were the 

Eastern U.S., Western U.S., and 

California. To calculate the co-benefits 

for the final standards, we multiplied 

the regional benefit-per-ton estimates 

generated from modeling of the 

proposed standards by the 

corresponding regional emission 

reductions for the final standards.1060

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 concentrationresponse functions, Krewski et al. 

(2009) 1061 and Lepeule et al. (2012).1062

These models assume that all fine 

particles, regardless of their chemical 

composition, are equally potent in 

causing premature mortality because the 

scientific evidence is not yet sufficient 

to allow differentiation of effect 

estimates by particle type. Even though 

we assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between PM2.5

precursors depending on the location 

and magnitude of their impact on PM2.5

concentrations, which drive population 

exposure. 

It is important to note that the 

magnitude of the PM2.5 and ozone cobenefits 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 study (Krewski et al., 2009) and 

one based on the extended Six Cities 

cohort study (Lepuele et al., 2012). We 

present the PM2.5 co-benefits results as 

a range based on benefit-per-ton 

estimates calculated using the 

concentration-response functions from 

these two epidemiology studies, but this 

range does not capture the full range of 

uncertainty inherent in the co-benefits 

estimates. In the RIA for this rule, which 

is available in the docket, we also 

include PM2.5 co-benefits estimates 

using benefit-per-ton estimates based on 

expert judgments of the effect of PM2.5

on premature mortality (Roman et al., 

2008) 1063 as a characterization of 

uncertainty regarding the PM2.5- 

mortality relationship. 

For the ozone co-benefits, we present 

the results as a range reflecting benefitper-ton estimates which use several 

different concentration-response 

functions for mortality, with the lower 

end of the range based on a benefit-perton estimate using the function from 

Bell et al. (2004) 1064 and the upper end 

based on a benefit-per-ton estimate 

using the function from Levy et al. 

(2005).1065 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, 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64933 

1066U.S. Environmental Protection Agency. 2009. 

Integrated Science Assessment for Particulate 

Matter (Final Report). Research Triangle Park, NC: 

National Center for Environmental Assessment, 

RTP Division. (EPA document number EPA–600–R– 

08–139F, December). Available at: http://

cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=216546. 

1067 In addition, site-specific emission reductions 

will depend upon how states implement the 

guidelines. 

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,1066

which evaluated the substantial body of 

published scientific literature, reflecting 

thousands of epidemiology, toxicology, 

and clinical studies that documents the 

association between elevated PM2.5

concentrations and adverse health 

effects, including increased premature 

mortality. This assessment, which was 

twice reviewed by the EPA’s 

independent Science Advisory Board, 

concluded that the scientific literature 

consistently finds that a no-threshold 

model most adequately portrays the PMmortality 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,1067 and 

thus, we are unable to estimate the 

percentage of premature mortality 

associated with this specific rule that is 

above the lowest measured PM2.5 levels 

(LML) for the two PM2.5 mortality 

epidemiology studies that form the basis 

for our analysis. As a surrogate measure 

of mortality impacts above the LML, we 

provide the percentage of the 

population exposed above the lowest 

measured PM2.5 level (LML) in each of 

the two studies, using the estimates of 

baseline projected PM2.5 from the air 

quality modeling for the proposed 

guidelines used to calculate the benefitper-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 

(mg/m3). Using the Lepeule et al. (2012) 

study, 46 percent of the population is 

exposed above the LML of 8 mg/m3. It 

is important to note that baseline 

exposure is only one parameter in the 

health impact function, along with 

baseline incidence rates, population, 

and change in air quality. 

Every benefit analysis examining the 

potential effects of a change in 

environmental protection requirements 

is limited, to some extent, by data gaps, 

model capabilities (such as geographic 

coverage) and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Despite these uncertainties, 

we believe the air quality co-benefit 

analysis for this rule provides a 

reasonable indication of the expected 

health benefits of the air pollution 

emission reductions for the illustrative 

analysis of the final standards under a 

set of reasonable assumptions. This 

analysis does not include the type of 

detailed uncertainty assessment found 

in the 2012 PM2.5 National Ambient Air 

Quality Standard (NAAQS) RIA (U.S. 

EPA, 2012) because we lack the 

necessary air quality input and 

monitoring data to conduct a complete 

benefits assessment. In addition, using a 

benefit-per-ton approach adds another 

important source of uncertainty to the 

benefits estimates. The 2012 PM2.5

NAAQS benefits analysis provides an 

indication of the sensitivity of our 

results to various assumptions. 

We note that the monetized cobenefits 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 guidelines. In addition, in the RIA 

for the final standards, we did not 

estimate changes in emissions of 

directly emitted particles. As a result, 

quantified PM2.5 related benefits are 

underestimated by a relatively small 

amount. In the RIA for the proposed 

guidelines, the benefits from reductions 

in directly emitted PM2.5 were less than 

10 percent of total monetized health cobenefits across all scenarios and years. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rule, which is available in the 

rulemaking docket. 

XII. Statutory and Executive Order 

Reviews 

Additional information about these 

Statutory and Executive Orders can be 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review, and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This final action is an economically 

significant regulatory action that was 

submitted to the OMB for review. Any 

changes made in response to OMB 

recommendations have been 

documented in the docket. The EPA 

prepared an analysis of the potential 

costs and benefits associated with this 

action. This analysis, which is 

contained in the ‘‘Regulatory Impact 

Analysis for Clean Power Plan Final 

Rule’’ (EPA–452/R–15–003, July 2015), 

is available in the docket and is briefly 

summarized in section XI of this 

preamble. 

Consistent with Executive Order 

12866 and Executive Order 13563, the 

EPA estimated the costs and benefits for 

illustrative compliance approaches of 

implementing the guidelines. The final 

rule establishes: (1) Carbon dioxide 

(CO2) emission performance rates for 

two source categories of existing fossil 

fuel-fired EGUs, fossil fuel-fired electric 

utility steam generating units and 

stationary combustion turbines, and (2) 

guidelines for the development, 

submittal and implementation of state 

plans that implement the CO2 emission 

performance rates. Actions taken to 

comply with the guidelines will also 

reduce the emissions of directly-emitted 

PM2.5, SO2 and NOX. The benefits 

associated with these PM2.5, SO2 and 

NOX reductions are referred to as cobenefits, as these reductions are not the 

primary objective of this rule. 

The EPA has used the social cost of 

carbon estimates presented in the 

Technical Support Document: 

Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (May 

2013, Revised July 2015) (‘‘current 

TSD’’) to analyze CO2 climate impacts of 

this rulemaking. We refer to these 

estimates, which were developed by the 

U.S. government, as ‘‘SC-CO2

estimates.’’ The SC-CO2 is an estimate of 

the monetary value of impacts 

associated with a marginal change in 

CO2 emissions in a given year. The four 

SC-CO2 estimates are associated with 

different discount rates (model average 

at 2.5 percent discount rate, 3 percent, 

and 5 percent; 95th percentile at 3 

percent), and each increases over time. 

In this summary, the EPA provides the 

estimate of climate benefits associated 

with the SC-CO2 value deemed to be 

central in the current TSD: The model 

average at 3 percent discount rate. 

In the final emission guidelines, the 

EPA has translated the source categoryVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00273 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

tkelley on DSK3SPTVN1PROD with BOOK 2
64934 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

specific CO2 emission performance rates 

into equivalent state-level rate-based 

and mass-based CO2 goals in order to 

maximize the range of choices that 

states will have in developing their 

plans. Because of the range of choices 

available to states and the lack of a 

priori knowledge about the specific 

choices states will make in response to 

the final goals, the Regulatory Impact 

Analysis (RIA) for this rule analyzed 

two implementation scenarios designed 

to achieve these goals, which we term 

the ‘‘rate-based’’ illustrative plan 

approach and the ‘‘mass-based’’ 

illustrative plan approach. 

It is very important to note that the 

differences between the analytical 

results for the rate-based and massbased illustrative plan approaches 

presented in the RIA may not be 

indicative of likely differences between 

the approaches if implemented by states 

and affected EGUs in response to the 

final guidelines. Rather, the two sets of 

analyses are intended to illustrate two 

different approaches to accomplish the 

emission performance rates finalized in 

the Clean Power Plan Final Rule. In 

other words, if one approach performs 

differently than the other on a given 

metric during a given time period, this 

does not imply this will apply in all 

instances in all time periods in all 

places. 

The EPA estimates that, in 2020, the 

final guidelines will yield monetized 

climate benefits (in 2011$) of 

approximately $2.8 billion for the ratebased approach and $3.3 billion for the 

mass-based approach (3 percent model 

average). For the rate-based approach, 

the air pollution health co-benefits in 

2020 are estimated to be $0.7 billion to 

$1.8 billion (2011$) for a 3 percent 

discount rate and $0.64 billion to $1.7 

billion (2011$) for a 7 percent discount 

rate. For the mass-based approach, the 

air pollution health co-benefits in 2020 

are estimated to be $2.0 billion to $4.8 

billion (2011$) for a 3 percent discount 

rate and $1.8 billion to $4.4 billion 

(2011$) for a 7 percent discount rate. 

The annual, illustrative compliance 

costs estimated by IPM and inclusive of 

demand-side EE program and 

participant costs and MRR costs in 

2020, are approximately $2.5 billion for 

the rate-based approach and $1.4 billion 

for the mass-based approach (2011$). 

The quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2020 are 

estimated to range from $1.0 billion to 

$2.1 billion (2011$) for the rate-based 

approach and from $3.9 billion to 6.7 

billion (2011$) for the mass-based 

approach, using a 3 percent discount 

rate (model average). 

The EPA estimates that, in 2025, the 

final guidelines will yield monetized 

climate benefits (in 2011$) of 

approximately $10 billion for the ratebased approach and $12 billion for the 

mass-based approach (3 percent model 

average). For the rate-based approach, 

the air pollution health co-benefits in 

2025 are estimated to be $7.4 billion to 

$18 billion (2011$) for a 3 percent 

discount rate and $6.7 billion to $16 

billion (2011$) for a 7 percent discount 

rate. For the mass-based approach, the 

air pollution health co-benefits in 2025 

are estimated to be $7.1 billion to $17 

billion (2011$) for a 3 percent discount 

rate and $6.5 billion to $16 billion 

(2011$) for a 7 percent discount rate. 

The annual, illustrative compliance 

costs estimated by IPM and inclusive of 

demand-side EE program and 

participant costs and MRR costs in 

2025, are approximately $1.0 billion for 

the rate-based approach and $3.0 billion 

for the mass-based approach (2011$). 

The quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2025 are 

estimated to range from $17 billion to 

$27 billion (2011$) for the rate-based 

approach and $16 billion to $26 billion 

(2011$) for the mass-based approach, 

using a 3 percent discount rate (model 

average). 

The EPA estimates that, in 2030, the 

final guidelines will yield monetized 

climate benefits (in 2011$) of 

approximately $20 billion for the ratebased approach and $20 billion for the 

mass-based approach (3 percent model 

average). For the rate-based approach, 

the air pollution health co-benefits in 

2030 are estimated to be $14 billion to 

$34 billion (2011$) for a 3 percent 

discount rate and $13 billion to $31 

billion (2011$) for a 7 percent discount 

rate. For the mass-based approach, the 

air pollution health co-benefits in 2030 

are estimated to be $12 billion to $28 

billion (2011$) for a 3 percent discount 

rate and $11 billion to $26 billion 

(2011$) for a 7 percent discount rate. 

The annual, illustrative compliance 

costs estimated by IPM and inclusive of 

demand-side EE program and 

participant costs and MRR costs in 

2030, are approximately $8.4 billion for 

the rate-based approach and $5.1 billion 

for the mass-based approach (2011$). 

The quantified net benefits (the 

difference between monetized benefits 

and compliance costs) in 2030 are 

estimated to range from $26 billion to 

$45 billion (2011$) for the rate-based 

approach and from $26 billion to $43 

billion (2011$) for the mass-based 

approach, using a 3 percent discount 

rate (model average). 

Tables 20 and 21 provide the 

estimates of the climate benefits, health 

co-benefits, compliance costs and net 

benefits of the final emission guidelines 

for rate-based and mass-based 

illustrative plan approaches, 

respectively. 

TABLE 21—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE FINAL

GUIDELINES IN 2020, 2025 AND 2030 UNDER THE RATE-BASED ILLUSTRATIVE PLAN APPROACH

[Billions of 2011$] a

Rate-based approach 

2020 2025 2030 

Climate Benefits b

5% discount rate ................................................................................................................... $0.80 $3.1 $6.4 

3% discount rate ................................................................................................................... $2.8 $10 $20 

2.5% discount rate ................................................................................................................ $4.1 $15 $29 

95th percentile at 3% discount rate ..................................................................................... $8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

3% ................ 7% ................ 3% ................ 7% ................ 3% ................ 7% 

Air Quality Health Co-benefits c ........................ $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 ... $6.7 to $16 ... $14 to $34 .... $13 to $31 

Compliance Costs d ..................................................................................................................... $2.5 $1.0 $8.4 


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Net Benefits e .................................................... $1.0 to $2.1 .. $1.0 to $2.0 .. $17 to $27 .... $16 to $25 .... $26 to $45 .... $25 to $43 

Non-Monetized Benefits .................................... Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury. 

Visibility impairment. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe 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 year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based on the analyses conducted 

for the proposed rule. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and 

ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality 

because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a 

discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program 

and participant costs. eThe estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). 

The RIA includes combined climate and health estimates based on additional discount rates. 

TABLE 22—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR THE FINAL

GUIDELINES IN 2020, 2025 AND 2030 UNDER THE MASS-BASED ILLUSTRATIVE PLAN APPROACH

[Billions of 2011$] a

Mass-based approach 

2020 2025 2030 

Climate Benefits b

5% discount rate .......................................................................................................................... $0.9 $3.6 $6.4 

3% discount rate .......................................................................................................................... $3.3 $12 $20 

2.5% discount rate ....................................................................................................................... $4.9 $17 $29 

95th percentile at 3% discount rate ............................................................................................. $9.7 $35 $60 

Air Quality Co-benefits Discount Rate 

3% ................ 7% ................ 3% ................ 7% ................ 3% ................ 7% 

Air Quality Health Co-benefits c .................. $2.0 to $4.8 .. $1.8 to $4.4 .. $7.1 to $17 ... $6.5 to $16 ... $12 to $28 .... $11 to $26 

Compliance Costs d ..................................................................................................................... $1.4 $3.0 $5.1 

Net Benefits e .................................................... $3.9 to $6.7 .. $3.7 to $6.3 .. $16 to $26 .... $15 to $24 .... $26 to $43 .... $25 to $40 

Non-Monetized Benefits .................................... Non-monetized climate benefits. 

Reductions in exposure to ambient NO2 and SO2. 

Reductions in mercury deposition. 

Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury. 

Visibility improvement. 

aAll are rounded to two significant figures, so figures may not sum. 

bThe 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 year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The 

co-benefits do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few 

percent based on the analyses conducted for the proposed rule. The range reflects the use of concentration-response functions from different 

epidemiology studies. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and 

ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality 

because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a 

discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program 

and participant costs. eThe estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). 

The RIA includes combined climate and health estimates based on additional discount rates. 

There are additional important 

benefits that the EPA could not 

monetize. Due to current data and 

modeling limitations, our estimates of 

the benefits from reducing CO2

emissions do not include important 

impacts like ocean acidification or 

potential tipping points in natural or 

managed ecosystems. Unquantified 


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benefits also include climate benefits 

from reducing emissions of non-CO2

GHGs (e.g., nitrous oxide and methane) 

and co-benefits from reducing direct 

exposure to SO2, NOX and hazardous air 

pollutants (e.g., mercury), as well as 

from reducing ecosystem effects and 

visibility impairment. Based upon the 

foregoing discussion, it remains clear 

that the benefits of this final action are 

substantial, and far exceed the costs. 

Additional details on benefits, costs, 

and net benefits estimates are provided 

in this RIA. 

B. Paperwork Reduction Act (PRA) 

The information collection 

requirements in this rule have been 

submitted for approval to OMB under 

the PRA. The Information Collection 

Request (ICR) document prepared by the 

EPA has been assigned the EPA ICR 

number 2503.02. You can find a copy of 

the ICR in the docket for this rule, and 

it is briefly summarized here. The 

information collection requirements are 

not enforceable until OMB approves 

them. 

This rule does not directly impose 

specific requirements on EGUs located 

in states or areas of Indian country. The 

rule also does not impose specific 

requirements on tribal governments that 

have affected EGUs located in their area 

of Indian country. For areas of Indian 

country, the rule establishes CO2

emission performance goals that could 

be addressed through either tribal or 

federal plans. A tribe would have the 

opportunity under the Tribal Authority 

Rule (TAR), but not the obligation, to 

apply to the EPA for Treatment as State 

(TAS) for purposes of a CAA section 

111(d) plan and, if approved by the 

EPA, to establish a CAA section 111(d) 

plan for its area of Indian country. To 

date, no tribe has requested or obtained 

TAS eligibility for purposes of a CAA 

section 111(d) plan. For areas of Indian 

country with affected EGUs where a 

tribe has not applied for TAS and 

submitted any needed plan, if the EPA 

determines that a CAA section 111(d) 

plan is necessary or appropriate, the 

EPA would have the responsibility to 

establish the plans. Because tribes are 

not required to implement section 

111(d) plans and because no tribe has 

yet sought TAS eligibility for this 

purpose, this action is not anticipated to 

impose any information collection 

burden on tribal governments over the 

3-year period covered by this ICR. 

This rule does impose specific 

requirements on state governments with 

affected EGUs. The information 

collection requirements are based on the 

recordkeeping and reporting burden 

associated with developing, 

implementing, and enforcing a plan to 

limit CO2 emissions from existing 

sources in the utility power sector. 

These recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to agency 

policies set forth in 40 CFR part 2, 

subpart B. 

The annual burden for this collection 

of information for the states (averaged 

over the first 3 years following 

promulgation) is estimated to be a range 

of 505,000 to 821,000 hours at a total 

annual labor cost of $35.8 to $58.1 

million. The lower bound estimate 

reflects the assumption that some states 

already have EE and RE programs in 

place. The higher bound estimate 

reflects the overly-conservative 

assumption that no states have EE and 

RE programs in place. 

The total annual burden for the 

federal government associated with the 

state collection of information (averaged 

over the first 3 years following 

promulgation) is estimated to be 54,000 

hours at a total annual labor cost of 

$3.00 million. Burden is defined at 5 

CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

OMB approves this ICR, the agency will 

announce that approval in the Federal 

Register and publish a technical 

amendment to 40 CFR part 9 to display 

the OMB control number for the 

approved information collection 

activities contained in this final rule. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. This action will not 

impose any requirements on small 

entities. Specifically, emission 

guidelines established under CAA 

section 111(d) do not impose any 

requirements on regulated entities and, 

thus, will not have a significant 

economic impact upon a substantial 

number of small entities. After emission 

guidelines are promulgated, states 

establish emission standards on existing 

sources, and it is those requirements 

that could potentially impact small 

entities. 

Our analysis here is consistent with 

the analysis of the analogous situation 

arising when the EPA establishes 

NAAQS, which do not impose any 

requirements on regulated entities. As 

here, any impact of a NAAQS on small 

entities would only arise when states 

take subsequent action to maintain and/ 

or achieve the NAAQS through their 

SIPs. See American Trucking Assoc. v. 

EPA, 175 F.3d 1029, 1043–45 (D.C. Cir. 

1999) (NAAQS do not have significant 

impacts upon small entities because 

NAAQS themselves impose no 

regulations upon small entities). 

Nevertheless, the EPA is aware that 

there is substantial interest in the rule 

among small entities and, as detailed in 

section III.A of the preamble to the 

proposed carbon pollution emission 

guidelines for existing EGUs (79 FR 

34845–34847; June 18, 2014) and in 

section II.D of the preamble to the 

proposed carbon pollution emission 

guidelines for existing EGUs in Indian 

Country and U.S. Territories (79 FR 

65489; November 4, 2014), has 

conducted an unprecedented amount of 

stakeholder outreach. As part of that 

outreach, agency officials participated 

in many meetings with individual 

utilities and electric utility associations, 

as well as industry leaders and trade 

association representatives from various 

industries. While formulating the 

provisions of the rule, the EPA 

considered the input provided over the 

course of the stakeholder outreach as 

well as the input provided in the many 

public comments. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. The 

emission guidelines do not impose any 

direct compliance requirements on 

EGUs located in states or areas of Indian 

country. As explained in section XII.B 

above, the rule also does not impose 

specific requirements on tribal 

governments that have affected EGUs 

located in their area of Indian country. 

The rule does impose specific 

requirements on state governments that 

have affected EGUs. Specifically, states 

are required to develop plans to 

implement the guidelines under CAA 

section 111(d) for affected EGUs. The 

burden for states to develop CAA 

section 111(d) plans in the 3-year period 

following promulgation of the rule was 

estimated and is listed in section XII.B 

above, but this burden is estimated to be 

below $100 million in any one year. 

Thus, this rule is not subject to the 

requirements of section 202 or section 

205 of the UMRA. 


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This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

Specifically, the state governments to 

which rule requirements apply are not 

considered small governments. 

In light of the interest among 

governmental entities, the EPA 

conducted outreach with national 

organizations representing state and 

local elected officials and tribal 

governmental entities while formulating 

the provisions of this rule. Sections III.A 

and XI.F of the preamble to the 

proposed carbon pollution emission 

guidelines for existing EGUs (79 FR 

34845–34847; June 18, 2014) and 

sections II.D and VI.F of the preamble to 

the proposed carbon pollution emission 

guidelines for existing EGUs in areas of 

Indian Country and U.S. Territories (79 

FR 65489; November 4, 2014) describes 

the extensive stakeholder outreach the 

EPA has conducted on setting emission 

guidelines for existing EGUs. The EPA 

considered the input provided over the 

course of the stakeholder outreach as 

well as the input provided in the many 

public comments when developing the 

provisions of these emission guidelines. 

E. Executive Order 13132: Federalism 

The EPA has concluded that this 

action may have federalism 

implications, pursuant to agency policy 

for implementing the Order, because it 

imposes substantial direct compliance 

costs on state or local governments, and 

the federal government will not provide 

the funds necessary to pay those costs. 

As discussed in the Supporting 

Statement found in the docket for this 

rulemaking, the development of state 

plans will entail many hours of staff 

time to develop and coordinate 

programs for compliance with the rule, 

as well as time to work with state 

legislatures as appropriate, to develop a 

plan submittal. Consistent with this 

determination, the EPA provides the 

following federalism summary impact 

statement. 

The EPA consulted with state and 

local officials early in the process of 

developing the proposed action to 

permit them to have meaningful and 

timely input into its development. As 

described in the Federalism discussion 

in the preamble to the proposed 

standards of performance for GHG 

emissions from new EGUs (79 FR 1501; 

January 8, 2014), the EPA consulted 

with state and local officials in the 

process of developing the proposed 

standards for newly constructed EGUs. 

This outreach addressed planned 

actions for new, reconstructed, modified 

and existing sources. The EPA invited 

the following 10 national organizations 

representing state and local elected 

officials to a meeting on April 12, 2011, 

in Washington, DC: (1) National 

Governors Association; (2) National 

Conference of State Legislatures, (3) 

Council of State Governments, (4) 

National League of Cities, (5) U.S. 

Conference of Mayors, (6) National 

Association of Counties, (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 preproposal update on the emission 

guidelines for existing EGUs and 

emission standards for modified and 

reconstructed EGUs. In addition, as 

described in section III.A of the 

preamble to the proposed carbon 

pollution emission guidelines for 

existing EGUs (79 FR 34845–34847; 

June 18, 2014), extensive stakeholder 

outreach conducted by the EPA allowed 

state leaders, including governors, state 

attorneys general, environmental 

commissioners, energy officers, public 

utility commissioners, and air directors, 

opportunities to engage with EPA 

officials and provide input regarding 

reducing carbon pollution from power 

plants. 

In the spirit of Executive Order 13132, 

and consistent with the EPA’s policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicited comment 

on the proposed action from state and 

local officials. The EPA received 

comments from over 400 entities 

representing state and local 

governments. 

Several themes emerged from state 

and local government comments. 

Commenters raised concerns with the 

building blocks that comprise the best 

system of emission reduction (BSER), 

including the stringency of the building 

blocks, and the timing of achieving 

interim CO2 levels. They also identified 

the potential for electric system 

reliability issues and stranded assets 

due to the proposed timeframe for plan 

submittals and CO2 emission 

reductions. In addition, states 

commented on state plan development 

and implementation topics, including 

state plan approaches, early actions, 

trading programs, interstate crediting for 

RE, and EPA guidance and outreach. 

Commenters identified overarching 

concerns regarding the stringency of the 

CO2 goals and the timeframe for 

achieving reductions that encompassed 

the building blocks, the BSER, and 

associated timing for achievement of 

interim CO2 levels. State commenters, in 

particular, identified changes to the 

stringency of the building blocks, 

concerns with the timeframe over which 

reductions must be achieved, and 

concerns with the approaches and 

measures used for the BSER. For the 

final rule, in response to stakeholder 

comments, the EPA has made 

refinements to the building blocks, the 

period of time over which measures are 

deployed, and the stringency of 

emission limitations that those 

measures can achieve in a practical and 

reasonable cost way. The final BSER 

reflects those refinements. 

To many commenters, the proposal’s 

2020 compliance date, together with the 

stringency of the interim CO2 goal, bore 

significant reliability implications. In 

this final rule, the agency is addressing 

those concerns via adjustments to the 

compliance timeframe (an 8-year 

interim period that begins in 2022) and 

to the approach for meeting interim CO2

emission performance rates (a glide path 

separated into three steps, 2022–2024, 

2025–2027, and 2028–2029), as well as 

a more gradual phase in of the emission 

reduction expectations. These 

adjustments provide more time for 

planning, consultation and decision 

making in the formulation of state plans 

and in EGUs’ choices of compliance 

strategies. The final rule also retains 

flexibilities presented in the proposal 

and offers additional opportunities, 

including opportunities for trading 

within and between states, and other 

multi-state compliance approaches that 

will further support electric system 

reliability. The EPA is also requiring 

each state to demonstrate in its final 

state that it has considered electric 

system reliability issues in developing 

its plan—and is providing the time to do 

so. Even with this foundation of 

flexibility in place, these final 

guidelines further provide states with 

the option of proposing amendments to 

approved plans in the event that 

unanticipated and significant reliability 

challenges arise. 

Commenters provided compelling 

information indicating that it will take 

longer than the agency initially 

anticipated to for states to complete the 

tasks necessary to finalize a state plan, 

including administrative and potential 

legislative processes. Recognizing this, 

as well as the urgent need for actions to 

reduce GHG emissions, the EPA is 

requiring states to make an initial 

submittal by September 6, 2016, and is 

allowing states two additional years to 


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submit a final plan, if justified (to be 

submitted by September 6, 2018). 

States commented on state plan 

development and implementation topics 

that included state plan approaches, 

early actions being taken into account, 

trading programs being allowed, 

interstate crediting for RE being 

allowed, and guidance and outreach 

being provided by the EPA. For the state 

plan approaches, commenters expressed 

concerns with the proposed ‘‘portfolio 

approach’’ for state plans, including 

concerns with enforceability of 

requirements, and identified a ‘‘state 

commitment approach’’ with backstop 

measures as an option for state plans. In 

this final rule, in response to 

stakeholder comments on the portfolio 

approach and alternative approaches, 

the EPA is finalizing a ‘‘state measures’’ 

approach that includes a requirement 

for the inclusion of backstop measures. 

State commenters supported 

providing incentives for states and 

utilities to deploy CO2-reducing 

investments, such as RE and demandside EE measures, as early as possible. 

The EPA recognizes the value of such 

early actions, and in this final rule is 

establishing the CEIP to provide 

opportunities for investment in RE and 

demand-side EE projects that deliver 

results in 2020 and/or 2021. 

Many state commenters supported the 

use of mass-based and rate-based 

emission trading programs in state 

plans, including interstate emission 

trading programs. The EPA also 

received a number of comments from 

states and stakeholders about the value 

of EPA support in developing and/or 

administering tracking systems to 

support state administration of ratebased and mass-based 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 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 implement multi-state trading or 

averaging approaches. 

In their comments, many states 

identified the need for the EPA to 

provide guidance, including guidance 

on RE and EE emission measurement 

and verification (EM&V), and to 

maintain regular contact/forums with 

states throughout the implementation 

process. To provide state and local 

governments and other stakeholders 

with an understanding of the rule 

requirements, and to provide 

efficiencies where possible and reduce 

the cost and administrative burden, the 

EPA will continue outreach throughout 

the plan development and submittal 

process. Outreach will include 

opportunities for states to participate in 

briefings, teleconferences, and meetings 

about the final rule. The EPA’s 10 

regional offices will continue to be the 

entry point for states and tribes to ask 

technical and policy questions. The 

agency will host (or partner with 

appropriate groups to co-host) a number 

of webinars about various components 

of the final rule during the first two 

months after the final rule is issued. The 

EPA will use information from this 

outreach process to inform the training 

and other tools that will be of most use 

to the states and tribes that are 

implementing the final rule. The EPA 

expects to issue guidance on specific 

topics, including evaluation, 

measurement and verification (EM&V) 

for RE and demand-side EE, statecommunity engagement, and resources 

and financial assistance for RE and 

demand-side EE. As guidance 

documents, tools, templates and other 

resources become available, the EPA, in 

consultation with the U.S. Department 

of Energy and other federal agencies, 

will continue to make these resources 

available via a dedicated Web site. 

A list of the state and local 

government commenters has been 

provided to OMB and has been placed 

in the docket for this rulemaking. In 

addition, the detailed response to 

comments from these entities is 

contained in the EPA’s response to 

comments document on this final 

rulemaking, which has also been placed 

in the docket for this rulemaking. 

As required by section 8(a) of 

Executive Order 13132, the EPA 

included a certification from its 

Federalism Official stating that the EPA 

had met the Executive Order’s 

requirements in a meaningful and 

timely manner when it sent the draft of 

this final action to OMB for review 

pursuant to Executive Order 12866. A 

copy of the certification is included in 

the public version of the official record 

for this final action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action has tribal implications. 

However, it will neither impose 

substantial direct compliance costs on 

federally recognized tribal governments, 

nor preempt tribal law. Tribes are not 

required to develop or adopt CAA 

programs, but they may apply to the 

EPA for treatment in a manner similar 

to states (TAS) and, if approved, do so. 

As a result, tribes are not required to 

develop plans to implement the 

guidelines under CAA section 111(d) for 

affected EGUs in their areas of Indian 

country. To the extent that a tribal 

government seeks and attains TAS 

status for that purpose, these emission 

guidelines would require that planning 

requirements be met and emission 

management implementation plans be 

executed by the tribes. The EPA notes 

that this rule does not directly impose 

specific requirements on affected EGUs, 

including those located in areas of 

Indian country, but provides guidance 

to any tribe approved by the EPA to 

address CO2 emissions from EGUs 

subject to section 111(d) of the CAA. 

The EPA also notes that none of the 

affected EGUs are owned or operated by 

tribal governments. 

As described in sections III.A and 

XI.F of the preamble to the proposed 

carbon pollution emission guidelines for 

existing EGUs (79 FR 34845–34847; 

June 18, 2014) and sections II.D and 

VI.F of the preamble to the proposed 

carbon pollution emission guidelines for 

existing EGUs in Indian Country and 

U.S. Territories (79 FR 65489; November 

4, 2014), the rule was developed after 

extensive and vigorous outreach to 

tribal governments. These tribes 

expressed varied points of view. Some 

tribes raised concerns about the impacts 

of the regulations on EGUs located in 

their areas of Indian country and the 

subsequent impact on jobs and revenue 

for their tribes. Other tribes expressed 

concern about the impact the 

regulations would have on the cost of 

water covered under treaty to their 

communities as a 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. 


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Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64939 

The EPA consulted with tribal 

officials under the EPA Policy on 

Consultation and Coordination with 

Indian Tribes early in the process of 

developing this action to permit them to 

have meaningful and timely input into 

its development. A summary of that 

consultation follows. 

Prior to issuing the supplemental 

proposal on November 4, 2014, the EPA 

consulted with tribes as follows. The 

EPA held a consultation with the Ute 

Tribe, the Crow Nation, and the 

Mandan, Hidatsa, Arikara (MHA) Nation 

on July 18, 2014. On August 22, 2014, 

the EPA held a consultation with the 

Fort Mojave Tribe. On September 15, 

2014, the EPA held a consultation with 

the Navajo Nation. The Navajo Nation 

sent a letter to the EPA on September 

18, 2014, summarizing the information 

presented at the consultation and the 

Navajo Nation’s position on the 

supplemental proposal. One issue raised 

by tribal officials was the potential 

impacts of the June 18, 2014 proposal 

and the supplemental proposal on tribes 

with budgets that are dependent on 

revenue from coal mines and power 

plants, as well as employment at the 

mines and power plants. The tribes 

noted the high unemployment rates and 

lack of access to basic services on their 

lands. Tribal officials also asked 

whether the rules will have any impact 

on a tribe’s ability to seek TAS. Tribal 

officials also expressed interest in 

agency actions with regard to facilitating 

power plant compliance with regulatory 

requirements. The Navajo Nation made 

the following recommendations in their 

letter of September 18, 2014: The Navajo 

Nation supports a mass-based CO2

emission standard based on the highest 

historical CO2 emissions since 1996; the 

Navajo Nation requests that the EPA 

grant the Navajo Nation carbon credits 

and that the Navajo Nation retains 

ownership and control of such credits; 

building block 2 is not appropriate for 

the Navajo Nation because there are no 

NGCC plants located on the Navajo 

Nation; building block 3 is not 

appropriate for the Navajo Nation 

because the Navajo people already 

receive virtually all of their electricity 

from carbon-free sources (mostly 

hydroelectric power) and their use of 

electricity is negligible compared to the 

generation at the power plants; building 

block 4 is not appropriate for the Navajo 

Nation because of the inadequate access 

to electricity, and the goal should allow 

for an increase in energy consumption 

on the Navajo Nation; the supplemental 

proposal should consider the useful life 

of the power plants located on the 

Navajo Nation; and the supplemental 

proposal should clarify that RE projects 

located within the Navajo Nation that 

provide electricity outside the Navajo 

Nation should be counted toward 

meeting the relevant state’s RE goals 

under the Clean Power Plan. 

After issuing the supplemental 

proposal, the EPA held additional 

consultation with tribes. On November 

18, 2014, the EPA held consultations 

with the following tribes: Fort 

McDowell Yavapai Nation, Fort Mojave 

Tribe, Hopi Tribe, Navajo Nation, and 

Ak-Chin Indian Community. A 

consultation with the Ute Indian Tribe 

of the Uintah and Ouray Reservation 

was held on December 16, 2014 and 

with the Gila River Indian Community 

on January 15, 2015. The Navajo Nation 

reiterated the concerns raised during the 

previous consultation. Several tribes 

also again indicated that they wanted to 

ensure they would be included in the 

development of any tribal or federal 

plans for areas of Indian country. The 

Fort Mojave Tribe and the Navajo 

Nation expressed concern with using 

data from 2012 as the basis for the goal 

for their areas of Indian country; in their 

view, that year was not representative 

for the affected EGU. On April 28, 2015, 

the EPA held an additional consultation 

with the Navajo Nation. The issues 

raised by the Navajo Nation during the 

consultation included whether the EPA 

has the authority to set less stringent 

standards on a case-by-case basis, and a 

suggested ‘‘parity glide path’’ that 

would account and adjust for the very 

low electricity usage by the Navajo 

Nation and promote Navajo Nation 

economic growth and demand. 

Furthermore, on July 7, 2015 the EPA 

conducted an additional consultation 

with the Navajo Nation. One of the goals 

of the consultation was for the new 

government of the Navajo Nation to 

deepen their understanding of the 

rulemaking. The questions raised by the 

nation had to do with goal setting and 

carbon credits, the timing of the 

rulemaking, and the proposed federal 

plan. Additionally, on July 14, 2015 the 

EPA conducted an additional 

consultation with the Fort Mojave Tribe. 

The Fort Mojave tribes expressed 

concerns that 2012 is not a 

representative year, that natural gasfired combined cycle power plants 

should be treated differently from coalfired power plants, and that the 

proposed goal for Fort Mojave was not 

appropriate. Additionally, they also 

expressed interest in being engaged in 

the federal plan process. Responses to 

these comments and others received are 

available in the Response to Comment 

Document that is in the docket for this 

rulemaking. As required by section 7(a), 

the EPA’s Tribal Consultation Official 

has certified that the requirements of the 

executive order have been met in a 

meaningful and timely manner. A copy 

of the certification is included in the 

docket for this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because it is an economically 

significant regulatory action as defined 

by Executive Order 12866, and the EPA 

believes that the environmental health 

or safety risk addressed by this action 

has a disproportionate effect on 

children. Accordingly, the agency has 

evaluated the environmental health and 

welfare effects of climate change on 

children. 

CO2 is a potent GHG that contributes 

to climate change and is emitted in 

significant quantities by fossil fuel-fired 

power plants. The EPA believes that the 

CO2 emission reductions resulting from 

implementation of these final 

guidelines, as well as substantial ozone 

and PM2.5 emission reductions as a cobenefit, will further improve children’s 

health. 

The assessment literature cited in the 

EPA’s 2009 Endangerment Finding 

concluded that certain populations and 

lifestages, including children, the 

elderly, and the poor, are most 

vulnerable to climate-related health 

effects. The assessment literature since 

2009 strengthens these conclusions by 

providing more detailed findings 

regarding these groups’ vulnerabilities 

and the projected impacts they may 

experience. 

These assessments describe how 

children’s unique physiological and 

developmental factors contribute to 

making them particularly vulnerable to 

climate change. Impacts to children are 

expected from heat waves, air pollution, 

infectious and waterborne illnesses, and 

mental health effects resulting from 

extreme weather events. In addition, 

children are among those especially 

susceptible to most allergic diseases, as 

well as health effects associated with 

heat waves, storms, and floods. 

Additional health concerns may arise in 

low income households, especially 

those with children, if climate change 

reduces food availability and increases 

prices, leading to food insecurity within 

households. 

More detailed information on the 

impacts of climate change to human 

health and welfare is provided in 

section II.A of this preamble. 


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64940 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

1068 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

1069Melillo, 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. 

https://www.ipcc.ch/report/ar5/wg2/. 

IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part B: Regional 

Aspects. Contribution of Working Group II to the 

Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, 

D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. 

Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 

Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 

MacCracken, P.R. Mastrandrea, and L.L. White 

(eds.)]. Cambridge University Press, 688 pp. https:// 

www.ipcc.ch/report/ar5/wg2/. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action, which is a significant 

regulatory action under EO 12866, is 

likely to have a significant effect on the 

supply, distribution, or use of energy. 

The EPA has prepared a Statement of 

Energy Effects for this action as follows. 

We estimate a 1 to 2 percent change in 

retail electricity prices on average across 

the contiguous U.S. in 2025, and a 22 

to 23 percent reduction in coal-fired 

electricity generation as a result of this 

rule. The EPA projects that utility power 

sector delivered natural gas prices will 

increase by up to 2.5 percent in 2030. 

For more information on the estimated 

energy effects, please refer to the 

economic impact analysis for this 

proposal. The analysis is available in 

the RIA, which is in the public docket. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This rulemaking does not involve 

technical standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the U.S. The EPA defines 

environmental justice as the fair 

treatment and meaningful involvement 

of all people regardless of race, color, 

national origin, or income with respect 

to the development, implementation, 

and enforcement of environmental laws, 

regulations, and policies. The EPA has 

this goal for all communities and 

persons across this Nation. It will be 

achieved 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).1068 As part of the 

Endangerment Finding, the 

Administrator considered climate 

change risks to minority populations 

and low-income populations, finding 

that certain parts of the population may 

be especially vulnerable based on their 

characteristics or circumstances. 

Populations that were found to be 

particularly vulnerable to climate 

change risks include the poor, the 

elderly, the very young, those already in 

poor health, the disabled, those living 

alone, and/or indigenous populations 

dependent on one or a few resources. 

See sections XII.F and XII.G, above, 

where the EPA discusses Consultation 

and Coordination with Tribal 

Governments and Protection of 

Children. The Administrator placed 

weight on the fact that certain groups, 

including children, the elderly, and the 

poor, are most vulnerable to climaterelated health effects. 

The record for the 2009 

Endangerment Finding summarizes the 

strong scientific evidence in the major 

assessment reports by the U.S. Global 

Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC) of the National 

Academies that the potential impacts of 

climate change raise environmental 

justice issues. These reports concluded 

that poor communities can be especially 

vulnerable to climate change impacts 

because they tend to have more limited 

adaptive capacities and are more 

dependent on climate-sensitive 

resources such as local water and food 

supplies. In addition, Native American 

tribal communities possess unique 

vulnerabilities to climate change, 

particularly those impacted by 

degradation of natural and cultural 

resources within established reservation 

boundaries and threats to traditional 

subsistence lifestyles. Tribal 

communities whose health, economic 

well-being, and cultural traditions that 

depend upon the natural environment 

will likely be affected by the 

degradation of ecosystem goods and 

services associated with climate change. 

The 2009 Endangerment Finding record 

also specifically noted that Southwest 

native cultures are especially vulnerable 

to water quality and availability 

impacts. Native Alaskan communities 

are already experiencing disruptive 

impacts, including coastal erosion and 

shifts in the range or abundance of wild 

species crucial to their livelihoods and 

well-being. 

The most recent assessments continue 

to strengthen scientific understanding of 

climate change risks to minority 

populations and low-income 

populations in the U.S.1069 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 U.S. These reports find 

that certain climate change related 

impacts—including heat waves, 

degraded air quality, and extreme 

weather events—have disproportionate 

effects on low-income populations and 

some communities of color, raising 

environmental justice concerns. Existing 

health disparities and other inequities 

in these communities increase their 

vulnerability to the health effects of 

climate change. In addition, assessment 

reports also find that climate change 

poses particular threats to health, wellbeing, and ways of life of indigenous 

peoples in the U.S. 

As the scientific literature presented 

above and as the 2009 Endangerment 

Finding illustrates, low income 

populations and some communities of 

color are especially vulnerable to the 

health and other adverse impacts of 

climate change. The EPA believes that 

communities will benefit from this final 

rulemaking because this action directly 

addresses the impacts of climate change 


tkelley on DSK3SPTVN1PROD with BOOK 2
Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 64941 

1070 ‘‘National Ambient Air Quality Standards for 

Particulate Matter, Final Rule,’’ 78 FR 3086 (Jan. 15, 

2013). 

1071U.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>. 

1072 Guidance on Considering Environmental 

Justice During the Development of Regulatory 

Actions. http://epa.gov/environmentaljustice/

resources/policy/considering-ej-in-rulemakingguide-final.pdf. May 2015. 

by limiting GHG emissions through the 

establishment of CO2 emission 

guidelines for existing affected fossil 

fuel-fired EGUs. 

In addition to reducing CO2

emissions, the guidelines finalized in 

this rulemaking would reduce other 

emissions from affected EGUs that 

reduce generation due to higher 

adoption of EE and RE. These emission 

reductions will include SO2 and NOX, 

which form ambient PM2.5 and ozone in 

the atmosphere, and HAP, such as 

mercury and hydrochloric acid. In the 

final rule revising the annual PM2.5

NAAQS,1070 the EPA identified lowincome populations as being a 

vulnerable population for experiencing 

adverse health effects related to PM 

exposures. Low-income populations 

have been generally found to have a 

higher prevalence of pre-existing 

diseases, limited access to medical 

treatment, and increased nutritional 

deficiencies, which can increase this 

population’s susceptibility to PMrelated effects.1071 In areas where this 

rulemaking reduces exposure to PM2.5, 

ozone, and methylmercury, low-income 

populations will also benefit from such 

emissions reductions. The RIA for this 

rulemaking, included in the docket for 

this rulemaking, provides additional 

information regarding the health and 

ecosystem effects associated with these 

emission reductions. 

Additionally, as outlined in the 

community and environmental justice 

considerations section IX of this 

preamble, the EPA has taken a number 

of actions to help ensure that this action 

will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on overburdened communities. The 

EPA consulted its May 2015, Guidance 

on Considering Environmental Justice 

During the Development of Regulatory 

Actions, when determining what actions 

to take.1072 As described in the 

community and environmental justice 

considerations section of this preamble 

the EPA also conducted a proximity 

analysis, which is available in the 

docket of this rulemaking and is 

discussed in section IX. Additionally, as 

outlined in sections I and IX of this 

preamble, the EPA has engaged with 

communities throughout this 

rulemaking and has devised a robust 

outreach strategy for continual 

engagement throughout the 

implementation phase of this 

rulemaking. 

K. Congressional Review Act (CRA) 

This final action is subject to the CRA, 

and the EPA will submit a rule report 

to each House of the Congress and to the 

Comptroller General of the United 

States. This action is a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

XIII. Statutory Authority 

The statutory authority for this action 

is provided by sections 111, 301, 302, 

and 307(d)(1)(C) of the CAA as amended 

(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)). 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: August 3, 2015. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60 of 

the Code of the Federal Regulations is 

amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for Part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 2. Add subpart UUUU to read as 

follows: 

Subpart—UUUU Emission Guidelines 

for Greenhouse Gas Emissions and 

Compliance Times for Electric Utility 

Generating Units 

Sec. 

Introduction 

60.5700 What is the purpose of this 

subpart? 

60.5705 Which pollutants are regulated by 

this subpart? 

60.5710 Am I affected by this subpart? 

60.5715 What is the review and approval 

process for my State plan? 

60.5720 What if I do not submit a plan or 

my plan is not approvable? 

60.5725 In lieu of a State plan submittal, are 

there other acceptable option(s) for a 

State to meet its CAA section 111(d) 

obligations? 

60.5730 Is there an approval process for a 

negative declaration letter? 

60.5735 What authorities will not be 

delegated to State, local, or tribal 

agencies? 

60.5736 Will the EPA impose any 

sanctions? 

60.5737 What is the Clean Energy Incentive 

Program and how do I participate? 

State and Multi-State Plan Requirements 

60.5740 What must I include in my 

federally enforceable State or multi-State 

plan? 

60.5745 What must I include in my final 

plan submittal? 

60.5750 Can I work with other States to 

develop a multi-State plan? 

60.5760 What are the timing requirements 

for submitting my plan? 

60.5765 What must I include in an initial 

submittal if requesting an extension for 

a final plan submittal? 

60.5770 What schedules, performance 

periods, and compliance periods must I 

include in my plan? 

60.5775 What emission standards must I 

include in my plan? 

60.5780 What State measures may I rely 

upon in support of my plan? 

60.5785 What is the procedure for revising 

my plan? 

60.5790 What must I do to meet my plan 

obligations? 

Emission Rate Credit Requirements 

60.5795 What affected EGUs qualify for 

generation of ERCs? 

60.5800 What other resources qualify for 

issuance of ERCs? 

60.5805 What is the process for the 

issuance of ERCs? 

60.5810 What applicable requirements are 

there for an ERC tracking system? 

Mass Allocations Requirements 

60.5815 What are the requirements for State 

allocation of allowances in a mass-based 

program? 

60.5820 What are my allowance tracking 

requirements? 

60.5825 What is the process for affected 

EGUs to demonstrate compliance in a 

mass-based program? 

Evaluation Measurement and Verification 

Plans and Monitoring and Verification 

Reports 

60.5830 What are the requirements for 

EM&V plans for eligible resources? 

60.5835 What are the requirements for M&V 

reports for eligible resources? 

Applicability of Plans to Affected EGUs 

60.5840 Does this subpart directly affect 

EGU owners and operators in my State? 

60.5845 What affected EGUs must I address 

in my State plan? 

60.5850 What EGUs are excluded from 

being affected EGUs? 

60.5855 What are the CO2 emission 

performance rates for affected EGUs? 

60.5860 What applicable monitoring, 

recordkeeping, and reporting 


tkelley on DSK3SPTVN1PROD with BOOK 2
64942 Federal Register / Vol. 80, No. 205 / Friday, October 23, 2015 / Rules and Regulations 

requirements do I need to include in my 

plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.5865 What are my recordkeeping 

requirements? 

60.5870 What are my reporting and 

notification requirements? 

60.5875 How do I submit information 

required by these emission guidelines to 

the EPA? 

Definitions 

60.5880 What definitions apply to this 

subpart? 

Table 1 to Subpart UUUU of Part 60—CO2

Emission Performance Rates (Pounds of 

CO2 per Net MWh) 

Table 2 to Subpart UUUU of Part 60— 

Statewide Rate-based CO2 Emission Goals 

(Pounds of CO2 per Net MWh) 

Table 3 to Subpart UUUU of Part 60— 

Statewide Mass-based CO2 Emission Goals 

(Short Tons of CO2) 

Table 4 to Subpart UUUU of Part 60— 

Statewide Mass-based CO2 Emission Goals 

plus New Source CO2 Emission 

Complement (Short Tons of CO2) 

Introduction 

§ 60.5700 What is the purpose of this 

subpart? 

This subpart establishes emission 

guidelines and approval criteria for 

State or multi-State plans that establish 

emission standards limiting greenhouse 

gas (GHG) emissions from an affected 

steam generating unit, integrated 

gasification combined cycle (IGCC), or 

stationary combustion turbine. An 

affected steam generating unit, IGCC, or 

stationary combustion turbine shall, for 

the purposes of this subpart, be referred 

to as an affected EGU. These emission 

guidelines are developed in accordance 

with section 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 Which pollutants are regulated 

by this subpart? 

(a) The pollutants regulated by this 

subpart are greenhouse gases. The 

emission guidelines for greenhouse 

gases established in this subpart are 

expressed as carbon dioxide (CO2) 

emission performance rates and 

equivalent statewide CO2 emission 

goals. 

(b) PSD and Title V Thresholds for 

Greenhouse Gases. 

(1) For the purposes of 

§ 51.166(b)(49)(ii), with respect to GHG 

emissions from facilities, the ‘‘pollutant 

that is subject to the standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

§ 51.166(b)(48) and in any State 

Implementation Plan (SIP) approved by 

the EPA that is interpreted to 

incorporate, or specifically incorporates, 

§ 51.166(b)(48) of this chapter. 

(2) For the purposes of 

§ 52.21(b)(50)(ii), with respect to GHG 

emissions from facilities regulated in 

the plan, the ‘‘pollutant that is subject 

to the standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in § 52.21(b)(49) of 

this chapter. 

(3) For the purposes of § 70.2 of this 

chapter, with respect to greenhouse gas 

emissions from facilities regulated in 

the plan, the ‘‘pollutant that is subject 

to any standard promulgated under 

section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is ‘‘subject to regulation’’ as 

defined in § 70.2 of this chapter. 

(4) For the purposes of § 71.2, with 

respect to greenhouse gas emissions 

from facilities regulated in the plan, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in § 71.2 of this 

chapter. 

§ 60.5710 Am I affected by this subpart? 

If you are the Governor of a State in 

the contiguous United States with one 

or more affected EGUs that commenced 

construction on or before January 8, 

2014, you must submit a State or multiState plan to the U.S. Environmental 

Protection Agency (EPA) that 

implements the emission guidelines 

contained in this subpart. If you are the 

Governor of a State in the contiguous 

United States with no affected EGUs for 

which construction commenced on or 

before January 8, 2014, in your State, 

you must submit a negative declaration 

letter in place of the State plan. 

§ 60.5715 What is the review and approval 

process for my plan? 

The EPA will review your plan 

according to § 60.27 except that under 

§ 60.27(b) the Administrator will have 

12 months after the date the final plan 

or plan revision (as allowed under 

§ 60.5785) is submitted, to approve or 

disapprove such plan or revision or 

each portion thereof. If you submit an 

initial submittal under § 60.5765(a) in 

lieu of a final plan submittal the EPA 

will follow the procedure in 

§ 60.5765(b). 

§ 60.5720 What if I do not submit a plan or 

my plan is not approvable? 

(a) If you do not submit an approvable 

plan the EPA will develop a Federal 

plan for your State according to § 60.27. 

The Federal plan will implement the 

emission guidelines contained in this 

subpart. Owners and operators of 

affected EGUs not covered by an 

approved plan must comply with a 

Federal plan implemented by the EPA 

for the State. 

(b) After a Federal plan has been 

implemented in your State, it will be 

withdrawn when your State submits, 

and the EPA approves, a final plan. 

§ 60.5725 In lieu of a State plan submittal, 

are there other acceptable option(s) for a 

State to meet its CAA section 111(d) 

obligations? 

A State may meet its CAA section 

111(d) obligations only by submitting a 

final State or multi-State plan submittal 

or a negative declaration letter (if 

applicable). 

§ 60.5730 Is there an approval process for 

a negative declaration letter? 

No. The EPA has no formal review 

process for negative declaration letters. 

Once your negative declaration letter 

has been received, the EPA will place a 

copy in the public docket and publish 

a notice in the Federal Register. If, at a 

later date, an affected EGU for which 

construction commenced on or before 

January 8, 2014 is found in your State, 

you will be found to have failed to 

submit a final plan as required, and a 

Federal plan implementing the emission 

guidelines contained in this subpart, 

when promulgated by the EPA, will 

apply to that affected EGU until you 

submit, and the EPA approves, a final 

State plan. 

§ 60.5735 What authorities will not be 

delegated to State, local, or tribal agencies? 

The authorities that will not be 

delegated to State, local, or tribal 

agencies are specified in paragraphs (a) 

and (b) of this section. 

(a) Approval of alternatives, not 

already approved by this subpart, to the 

CO2 emission performance rates in 

Table 1 to this subpart established 

under § 60.5855. 

(b) Approval of alternatives, not 

already approved by this subpart, to the 

CO2 emissions goals in Tables 2, 3 and 

4 to this subpart established under 

§ 60.5855. 

§ 60.5736 Will the EPA impose any 

sanctions? 

No. The EPA will not withhold any 

existing federal funds from a State on 

account of a State’s failure to submit, 

implement, or enforce an approvable 

plan or plan revision, or to meet any 

other requirements under this subpart or 

subpart B of this part. 


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§ 60.5737 What is the Clean Energy 

Incentive Program and how do I 

participate? 

(a) This subpart establishes the Clean 

Energy Incentive Program (CEIP). 

Participation in this program is 

optional. The program enables States to 

award early action emission rate credits 

(ERCs) and allowances to eligible 

renewable energy (RE) or demand-side 

energy efficiency (EE) projects that 

generate megawatt hours (MWh) or 

reduce end-use energy demand during 

2020 and/or 2021. Eligible projects are 

those that: 

(1) Are located in or benefit a state 

that has submitted a final state plan that 

includes requirements establishing its 

participation in the CEIP; and 

(2) Commence construction in the 

case of RE, or commence operation in 

the case of demand-side EE, following 

the submission of a final state plan to 

the EPA, or after September 6, 2018 for 

a state that chooses not to submit a final 

state plan by that date; and either 

(3) Generate metered MWh from any 

type of wind or solar resources; or 

(4) Result in quantified and verified 

electricity savings (MWh) through 

demand-side EE implemented in lowincome communities. 

(b) The EPA will award matching 

ERCs or allowances to States that award 

early action ERCs or allowances, up to 

a match limit equivalent to 300 million 

tons of CO2 emissions. The awards will 

be executed as follows: 

(1) For RE projects that generate 

metered MWh from wind or solar 

resources: For every two MWh 

generated, the project will receive one 

early action ERC (or the equivalent 

number of allowances) from the State, 

and the EPA will provide one matching 

ERC (or the equivalent number of 

allowances) to the State to award to the 

project. 

(2) For EE projects implemented in 

low-income communities: For every two 

MWh in end-use demand savings 

achieved, the project will receive two 

early action ERCs (or the equivalent 

number of allowances) from the State, 

and the EPA will provide two matching 

ERCs (or the equivalent number of 

allowances) to the State to award to the 

project. 

(c) You may participate in this 

program by including in your State plan 

a mechanism that enables issuance of 

early action ERCs or allowances by the 

State to parties effectuating reductions 

in the calendar years 2020 and/or 2021 

in a manner that would have no impact 

on the emission performance of affected 

EGUs required to meet rate-based or 

mass-based emission standards during 

the performance periods. This 

mechanism is not required to account 

for matching ERCs or allowances that 

may be issued to the State by the EPA. 

(d) If you are submitting an initial 

submittal by September 6, 2016, and 

you intend to participate in the CEIP, 

you must include a non-binding 

statement of intent to participate in the 

program. If you are submitting a final 

plan by September 6, 2016, and you 

intend to participate in the CEIP, your 

State plan must either include 

requirements establishing the necessary 

infrastructure to implement such a 

program and authorizing your affected 

EGUs to use early action allowances or 

ERCs as appropriate, or you must 

include a non-binding statement of 

intent as part of your supporting 

documentation and revise your plan to 

include the appropriate requirements at 

a later date. 

(e) If you intend to participate in the 

CEIP, your final State plan, or plan 

revision if applicable, must require that 

projects eligible under this program be 

evaluated, monitored, and verified, and 

that resulting ERCs or allowances be 

issued, per applicable requirements of 

the State plan approved by the EPA as 

meeting § 60.5805 through § 60.5835. 

State and Multi-State Plan 

Requirements 

§ 60.5740 What must I include in my 

federally enforceable State or multi State 

plan? 

(a) You must include the components 

described in paragraphs (a)(1) through 

(5) of this section in your plan 

submittal. The final plan must meet the 

requirements and include the 

information required under § 60.5745. 

(1) Identification of affected EGUs. 

Consistent with § 60.25(a), you must 

identify the affected EGUs covered by 

your plan and all affected EGUs in your 

State that meet the applicability criteria 

in § 60.5845. In addition, you must 

include an inventory of CO2 emissions 

from the affected EGUs during the most 

recent calendar year for which data is 

available prior to the submission of the 

plan. 

(2) Emission standards. You must 

include an identification of all emission 

standards for each affected EGU 

according to § 60.5775, compliance 

periods for each emission standard 

according to § 60.5770, and a 

demonstration that the emission 

standards, when taken together, achieve 

the applicable CO2 emission 

performance rates or CO2 emission goals 

described in § 60.5855. Allowance 

systems are an acceptable form of 

emission standards under this subpart. 

(i) Your plan does not need to include 

corrective measures specified in 

paragraph (a)(2)(ii) of this section if your 

plan: 

(A) Imposes emission standards on all 

affected EGUs that, assuming full 

compliance by all affected EGUs, 

mathematically assure achievement of 

the CO2 emission performance rates in 

the plan for each plan period; 

(B) Imposes emission standards on all 

affected EGUS that, assuming full 

compliance by all affected EGUs, 

mathematically assure achievement of 

the CO2 emission goals; or 

(C) Imposes emission standards on all 

affected EGUs that, assuming full 

compliance by all affected EGUs, in 

conjunction with applicable 

requirements under state law for EGUs 

subject to subpart TTTT of this subpart, 

assuming the applicable requirements 

under state law are met by all EGUs 

subject to subpart TTTT of this subpart, 

achieve the applicable mass-based CO2

emission goals plus new source CO2

emission complement allowed for in 

§ 60.5790(b)(5). 

(ii) If your plan does not meet the 

requirements of (a)(2)(i) or (iii) of this 

section, your plan must include the 

requirement for corrective measures to 

be implemented if triggered. Upon 

triggering corrective measures, if you do 

not already have them included in your 

approved State plan, you must submit 

corrective measures to EPA for approval 

as a plan revision per the requirements 

of § 60.5785(c). These corrective 

measures must ensure that the interim 

period and final period CO2 emission 

performance rates or CO2 emission goals 

are achieved by your affected EGUs, as 

applicable, and must achieve additional 

emission reductions to offset any 

emission performance shortfall. Your 

plan must include the requirement that 

corrective measures be triggered and 

implemented according to paragraphs 

(a)(2)(ii)(A) through (H) of this section. 

(A) Your plan must include a trigger 

for an exceedance of an interim step 1 

or interim step 2 CO2 emission 

performance rate or CO2 emission goal 

by 10 percent or greater, either on 

average or cumulatively (if applicable). 

(B) Your plan must include a trigger 

for an exceedance of an interim step 1 

goal or interim step 2 goal of 10 percent 

or greater based on either reported CO2

emissions with applied plus or minus 

net allowance export or import 

adjustments (if applicable), or based on 

the adjusted CO2 emission rate (if 

applicable). 

(C) Your plan must include a trigger 

for a failure to meet an interim period 

goal based on reported CO2 emissions 

with applied plus or minus net 

allowance export or import adjustments 


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(if applicable), or based on the adjusted 

CO2 emission rate (if applicable). 

(D) Your plan must include a trigger 

for a failure to meet the interim period 

or any final reporting period CO2

emission performance rate or CO2

emission goal, either on average or 

cumulatively (as applicable). 

(E) Your plan must include a trigger 

for a failure to meet any final reporting 

period goal based on reported CO2

emissions with applied plus or minus 

net allowance export or import 

adjustments (if applicable). 

(F) Your plan must include a trigger 

for a failure to meet the interim period 

CO2 emission performance rate or CO2

emission goal based on the adjusted CO2

emission rate (if applicable). 

(G) Your plan must include a trigger 

for a failure to meet any final reporting 

period CO2 emission performance rate 

or CO2 emission goal based on the 

adjusted CO2 emission rate (if 

applicable). 

(H) A net allowance import 

adjustment represents the CO2

emissions (in tons) equal to the number 

of net imported CO2 allowances. This 

adjustment is subtracted from reported 

CO2 emissions. Under this adjustment, 

such allowances must be issued by a 

state with an emission budget trading 

program that only applies to affected 

EGUs (or affected EGUs plus EGUs 

covered by subpart TTTT of this part as 

applicable). A net allowance export 

adjustment represents the CO2

emissions (in tons) equal to the number 

of net exported CO2 allowances. This 

adjustment is added to reported CO2

emissions. 

(iii) If your plan relies upon State 

measures, in addition to or in lieu of 

emission standards on your affected 

EGUs, then the final State plan must 

include the requirements in paragraph 

(a)(3) of this section and the submittal 

must include the information listed in 

§ 60.5745(a)(6). 

(iv) If your plan requires emission 

standards in addition to relying upon 

State measures, then you must 

demonstrate that the emission standards 

and State measures, when taken 

together, result in the achievement of 

the applicable mass-based CO2 emission 

goal described in § 60.5855 by your 

State’s affected EGUs. 

(3) State measures backstop. If your 

plan relies upon State measures, you 

must submit, as part of the plan in lieu 

of the requirements in paragraph 

(a)(2)(i) and (ii) of this section, a 

federally enforceable backstop that 

includes emission standards for affected 

EGUs that will be put into place, if there 

is a triggering event listed in paragraph 

(a)(3)(i) of this section, within 18 

months of the due date of the report 

required in § 60.5870(b). The emission 

standards on the affected EGUs as part 

of the backstop must be able to meet 

either the CO2 emission performance 

rates or mass-based or rate-based CO2

emission goal for your State during the 

interim and final periods. You must 

either submit, along with the backstop 

emission standards, provisions to adjust 

the emission standards to make up for 

the prior emission performance 

shortfall, such that no later plan 

revision to modify the emission 

standards is necessary in order to 

address the emission performance 

shortfall, or you must submit, as part of 

the final plan, backstop emission 

standards that assure affected EGUs 

would achieve your State’s CO2

emission performance rates or emission 

goals during the interim and final 

periods, and then later submit 

appropriate revisions to the backstop 

emission standards adjusting for the 

shortfall through the State plan revision 

process described in § 60.5785. The 

backstop must also include the 

requirements in paragraphs (a)(3)(i) 

through (iii) of this section, as 

applicable. 

(i) You must include a trigger for the 

backstop to go into effect upon: 

(A) A failure to meet a programmatic 

milestone; 

(B) An exceedance of 10 percent or 

greater of an interim step 1 goal or 

interim step 2 goal based on reported 

CO2 emissions, with applied plus or 

minus net allowance export or import 

adjustments (if applicable); 

(C) A failure to meet the interim 

period goal based on reported CO2

emissions, with applied plus or minus 

net allowance export or import 

adjustments (if applicable); or 

(D) A failure to meet any final 

reporting period goal based on reported 

CO2 emissions, with applied plus or 

minus net allowance export or import 

adjustments (if applicable). 

(ii) You may include in your plan any 

additional triggers so long as they do not 

reduce the stringency of the triggers 

required under paragraph (a)(3)(i) of this 

section. 

(iii) 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 all applicable monitoring, 

reporting and recordkeeping 

requirements for each affected EGU and 

the requirements must be consistent 

with or no less stringent than the 

requirements specified in § 60.5860. 

(5) State reporting. You must include 

in your plan a description of the 

process, contents, and schedule for State 

reporting to the EPA about plan 

implementation and progress, including 

information required under § 60.5870. 

(i) You must include in your plan a 

requirement for a report to be submitted 

by July 1, 2021, that demonstrates that 

the State has met, or is on track to meet, 

the programmatic milestone steps 

indicated in the timeline required in 

§ 60.5770. 

(b) You must follow the requirements 

of subpart B of this part and 

demonstrate that they were met in your 

State plan. However, the provisions of 

§ 60.24(f) shall not apply. 

§ 60.5745 What must I include in my final 

plan submittal? 

(a) In addition to the components of 

the plan listed in § 60.5740, a final plan 

submittal to the EPA must include the 

information in paragraphs (a)(1) through 

(13) of this section. This information 

must be submitted to the EPA as part of 

your final plan submittal but will not be 

codified as part of the federally 

enforceable plan upon approval by EPA. 

(1) You must include a description of 

your plan approach and the geographic 

scope of the plan (i.e., State or multiState, geographic boundaries related to 

the plan elements), including, if 

applicable, identification of multi-State 

plan participants. 

(2) You must identify CO2 emission 

performance rates or equivalent 

statewide CO2 emission goals that your 

affected EGUs will achieve. If the 

geographic scope of your plan is a single 

State, then you must identify CO2

emission performance rates or emission 

goals according to § 60.5855. If your 

plan includes multiple States and you 

elect to set CO2 emission goals, you 

must identify CO2 emission goals 

calculated according to § 60.5750. 

(i) You must specify in the plan 

submittal the CO2 emission performance 

rates or emission goals that affected 

EGUs will meet for the interim period, 

each interim step, and the final period 

(including each final reporting period) 

pursuant to § 60.5770. 

(ii) [Reserved] 

(3) You must include a demonstration 

that the affected EGUs covered by the 

plan are projected to achieve the CO2

emission performance rates or CO2

emission goals described in § 60.5855. 

(4) You must include a demonstration 

that each affected EGU’s emission 

standard is quantifiable, nonVerDate Sep<11>2014 20:52 Oct 22, 2015 Jkt 238001 PO 00000 Frm 00284 Fmt 4701 Sfmt 4700 E:\FR\FM\23OCR3.SGM 23OCR3

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duplicative, permanent, verifiable, and 

enforceable according to § 60.5775. 

(5) If your plan includes emission 

standards on your affected EGUs 

sufficient to meet either the CO2

emission performance rates or CO2

emission goals, you must include in 

your plan submittal the information in 

paragraphs (a)(5)(i) through (v) of this 

section as applicable. 

(i) If your plan applies separate ratebased CO2 emission standards for 

affected EGUs (in lbs CO2/MWh) that 

are equal to or lower than the CO2

emission performance rates listed in 

Table 1 of this subpart or uniform ratebased CO2 emission standards equal to 

or lower than the rate-based CO2

emission goals listed in Table 2 of this 

subpart, then no additional 

demonstration is required beyond 

inclusion of the emission standards in 

the plan. 

(ii) If a plan applies rate-based 

emission standards to individual 

affected EGUs at a lbs CO2/MWh rate 

that differs from the CO2 emission 

performance rates in Table 1 of this 

subpart or the State’s rate-based CO2

emission goal in Table 2 of this subpart, 

then a further demonstration is required 

that the application of the CO2 emission 

standards will achieve the CO2 emission 

performance rates or State rate-based 

CO2 emission goal. You must 

demonstrate through a projection that 

the adjusted weighted average CO2

emission rate of affected EGUs, when 

weighted by generation (in MWh), will 

be equal to or less than the CO2

emission performance rates or the ratebased CO2 emission goal. This 

projection must address the interim 

period and the final period. The 

projection in the plan submittal must 

include the information listed in 

paragraph (a)(5)(v) of this section and in 

addition the following: 

(A) An analysis of the change in 

generation of affected EGUs given the 

compliance costs and incentives under 

the application of different emission 

rate standards across affected EGUs in a 

State; 

(B) A projection showing how 

generation is expected to shift between 

affected EGUs and across affected EGUs 

and non-affected EGUs over time; 

(C) Assumptions regarding the 

availability and anticipated use of the 

MWh of electricity generation or 

electricity savings from eligible 

resources that can be issued ERCs; 

(D) The specific calculation (or 

assumption) of how eligible resource 

MWh of electricity generation or savings 

are being used in the projection to 

adjust the reported CO2 emission rate of 

affected EGUs; 

(E) If a state plan provides for the 

ability of renewable energy resources 

located in states with mass-based plans 

to be issued ERCs, consideration in the 

projection that such resources must 

meet geographic eligibility 

requirements, consistent with 

§ 60.5800(a); and 

(F) Any other applicable assumptions 

used in the projection. 

(iii) If a plan establishes mass-based 

emission standards for affected EGUs 

that cumulatively do not exceed the 

State’s EPA-specified mass CO2

emission goal, then no additional 

demonstration is required beyond 

inclusion of the emission standards in 

the plan. 

(iv) If a plan applies mass-based 

emission standards to individual 

affected EGUs that cumulatively exceed 

the State’s EPA-specified mass CO2

emission goal, then you must include a 

demonstration that your mass-based 

emission program will be designed such 

that compliance by affected EGUs 

would achieve the State mass-based CO2

emission goals. This demonstration 

includes the information listed in 

paragraph (a)(5)(v) of this section. 

(v) Your plan demonstration to be 

included in your plan submittal, if 

applicable, must include the 

information listed in paragraphs 

(a)(5)(v)(A) through (L) of this section. 

(A) A summary of each affected EGU’s 

anticipated future operation 

characteristics, including: 

(1) Annual generation; 

(2) CO2 emissions; 

(3) Fuel use, fuel prices (when 

applicable), fuel carbon content; 

(4) Fixed and variable operations and 

maintenance costs (when applicable); 

(5) Heat rates; and 

(6) Electric generation capacity and 

capacity factors. 

(B) An identification of any planned 

new electric generating capacity. 

(C) Analytic treatment of the potential 

for building unplanned new electric 

generating capacity. 

(D) A timeline for implementation of 

EGU-specific actions (if applicable). 

(E) All wholesale electricity prices. 

(F) A geographic representation 

appropriate for capturing impacts and/ 

or changes in the electric system. 

(G) A time period of analysis, which 

must extend through at least 2031. 

(H) An anticipated electricity demand 

forecast (MWh load and MW peak 

demand) at the State and regional level, 

including the source and basis for these 

estimates, and, if appropriate, 

justification and documentation of 

underlying assumptions that inform the 

development of the demand forecast 

(e.g., annual economic and demand 

growth rate or population growth rate). 

(I) A demonstration that each 

emission standard included in your 

plan meets the requirements of 

§ 60.5775. 

(J) Any ERC or emission allowance 

prices, when applicable. 

(K) An identification of planning 

reserve margins. 

(L) Any other applicable assumptions 

used in the projection. 

(6) If your plan relies upon State 

measures, in addition to or in lieu of the 

emission standards required by 

paragraph § 60.5740(a)(2), the final State 

plan submittal must include the 

information under paragraphs (a)(5)(v) 

and (a)(6)(i) through (v) of this section. 

(i) You must include a description of 

all the State measures the State will rely 

upon to achieve the applicable CO2

emission goals required under 

§ 60.5855(e), the projected impacts of 

the State measures over time, the 

applicable State laws or regulations 

related to such measures, and 

identification of parties or entities 

subject to or 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 CO2 emissions measured at 

an affected EGU’s stack, you must also 

demonstrate how the minimum 

emission, monitoring and verification 

(EM&V) requirements listed under 

§ 60.5795 that apply to those programs 

and projects will be met. 

(iii) You must demonstrate that 

federally enforceable emission 

standards for affected EGUs in 

conjunction with any State measures 

relied upon for your plan, are sufficient 

to achieve the mass-based CO2 emission 

goal for the interim period, each interim 

step in that interim period, the final 

period, and each final reporting period. 

In addition, you must demonstrate that 

each emission standard included in 

your plan meets the requirements of 

§ 60.5775 and each State measure 

included in your plan submittal meets 

the requirements of § 60.5780. 

(iv) You must include a CO2

performance projection of your State 

measures that shows how the measures, 

whether alone or in conjunction with 

any federally enforceable CO2 emission 

standards for affected EGUs, will result 

in the achievement of the future CO2

performance at affected EGUs. Elements 

of this projection must include those 

specified in paragraph (a)(5)(v) of this 

section, as applicable, and the following 

for the interim period and the final 

period: 


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(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 identification of Stateenforceable measures with electricity 

savings and RE generation, in MWh, 

expected for individual and collective 

measures and any assumptions related 

to the quantification of the MWh, as 

applicable. 

(7) Your plan submittal must include 

a demonstration that the reliability of 

the electrical grid has been considered 

in the development of your plan. 

(8) Your plan submittal must include 

a timeline with all the programmatic 

milestone steps the State intends to take 

between the time of the State plan 

submittal and January 1, 2022 to ensure 

the plan is effective as of January 1, 

2022. 

(9) Your plan submittal must 

adequately demonstrate that your State 

has the legal authority (e.g., through 

regulations or legislation) and funding 

to implement and enforce each 

component of the State plan submittal, 

including federally enforceable 

emission standards for affected EGUs, 

and State measures as applicable. 

(10) Your State plan submittal must 

demonstrate that each interim step goal 

required under § 60.5855(c), will be met 

and include in its supporting 

documentation, if applicable, a 

description of the analytic process, 

tools, methods, and assumptions used to 

make this demonstration. 

(11) Your plan submittal must include 

certification that a hearing required 

under § 60.23(c)(1) on the State plan 

was held, a list of witnesses and their 

organizational affiliations, if any, 

appearing at the hearing, and a brief 

written summary of each presentation or 

written submission, pursuant to the 

requirements of § 60.23(d) and (f). 

(12) Your plan submittal must include 

documentation of any conducted 

community outreach and community 

involvement, including engagement 

with vulnerable communities. 

(13) Your plan submittal must include 

supporting material for your plan 

including: 

(i) Materials demonstrating the State’s 

legal authority and funding to 

implement and enforce each component 

of its plan, including emissions 

standards and/or State measures that the 

plan relies upon; 

(ii) Materials supporting that the CO2

emission performance rates or CO2

emission goals will be achieved by 

affected EGUs identified under the plan, 

according to paragraph (a)(3) of this 

section; 

(iii) Materials supporting any 

calculations for CO2 emission goals 

calculated according to § 60.5855, if 

applicable; and 

(iv) Any other materials necessary to 

support evaluation of the plan by the 

EPA. 

(b) You must submit your final plan 

to the EPA electronically according to 

§ 60.5875. 

§ 60.5750 Can I work with other States to 

develop a multi-State plan? 

A multi-State plan must include all 

the required elements for a plan 

specified in § 60.5740(a). A multi-State 

plan must meet the requirements of 

paragraphs (a) and (b) of this section. 

(a) The multi-State plan must 

demonstrate that all affected EGUs in all 

participating States will meet the CO2

emission performance rates listed in 

Table 1 of this subpart or an equivalent 

CO2 emission goal according to 

paragraphs (a)(1) or (2) of this section. 

States may only follow the procedures 

in (a)(1) or (2) if they have functionally 

equivalent requirements meeting 

§ 60.5775 and § 60.5790 included in 

their plans. 

(1) For States electing to demonstrate 

performance with a CO2 emission ratebased goal, the CO2 emission goals 

identified in the plan according to 

§ 60.5855 will be an adjusted weighted 

(by net energy output) average lbs CO2/ 

MWh emission rate to be achieved by all 

affected EGUs in the multi-State area 

during the plan periods; or 

(2) For States electing to demonstrate 

performance with a CO2 emission massbased goal, the CO2 emission goals 

identified in the multi-State plan 

according to § 60.5855 will be total mass 

CO2 emissions by all affected EGUs in 

the multi-State area during the plan 

periods, representing the sum of all 

individual mass CO2 goals for states 

participating in the multi-state plan. 

(b) Options for submitting a multiState plan include the following: 

(1) States participating in a multiState plan may submit one multi-State 

plan submittal on behalf of all 

participating States. The joint submittal 

must be signed electronically, according 

to § 60.5875, by authorized officials for 

each of the States participating in the 

multi-State plan. In this instance, the 

joint submittal will have the same legal 

effect as an individual submittal for 

each participating State. The joint 

submittal must address plan 

components that apply jointly for all 

participating States and components 

that apply for each individual State in 

the multi-State plan, including 

necessary State legal authority to 

implement the plan, such as State 

regulations and statutes. 

(2) States participating in a multiState plan may submit a single plan 

submittal, signed by authorized officials 

from each participating State, which 

addresses common plan elements. Each 

participating State must, in addition, 

provide individual plan submittals that 

address State-specific elements of the 

multi-State plan. 

(3) States participating in a multiState 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. 

(c) A State may elect to participate in 

more than one multi-State plan. If your 

State elects to participate in more than 

one multi-State plan then you must 

identify in the State plan submittal 

required under § 60.5745, the subset of 

affected EGUs that are subject to the 

specific multi-State plan or your State’s 

individual plan. An affected EGU can 

only be subject to one plan. 

(d) A State may elect to allow its 

affected EGUs to interact with affected 

EGUs in other States through massbased trading programs or a rate-based 

trading program without entering into a 

formal multi-State plan allowed for 

under this section, so long as such 

programs are part of an EPA-approved 

state plan and meet the requirements of 

paragraphs (d)(1) and (2) of this section, 

as applicable. 

(1) For States that elect to do massbased trading under this option the 

State must indicate in its plan that its 

emission budget trading program will be 

administered using an EPA-approved 

(or EPA-administered) emission and 

allowance tracking system. 

(2) For States that elect to use a ratebased trading program which allows the 

affected EGUs to use ERCs from other 

State rate-based trading programs, the 

plan must require affected EGUs within 

their State to comply with emission 

standards equal to the sub-category CO2

emission performance rates in Table 1 of 

this subpart. 

§ 60.5760 What are the timing 

requirements for submitting my plan? 

(a) You must submit a final plan with 

the information required under 

§ 60.5745 by September 6, 2016, unless 

you are submitting an initial submittal, 


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allowed under § 60.5765, in lieu of a 

final State plan submittal, according to 

paragraph (b) of this section. 

(b) For States seeking a two year 

extension for a final plan submittal, you 

must include the information in 

§ 60.5765(a) in an initial submittal by 

September 6, 2016, to receive an 

extension to submit your final State 

plan submittal by September 6, 2018. 

(c) You must submit all information 

required under paragraphs (a) and (b) of 

this section according to the electronic 

reporting requirements in § 60.5875. 

§ 60.5765 What must I include in an initial 

submittal if requesting an extension for a 

final plan submittal? 

(a) You must sufficiently demonstrate 

that your State is able to undertake steps 

and processes necessary to timely 

submit a final plan by the extended date 

of September 6, 2018, by addressing the 

following required components in an 

initial submittal by September 6, 2016, 

if requesting an extension for a final 

plan submittal: 

(1) An identification of final plan 

approach or approaches under 

consideration and a description of 

progress made to date on the final plan 

components; 

(2) An appropriate explanation of why 

the State requires additional time to 

submit a final plan by September 6, 

2018; and 

(3) A demonstration or description of 

the opportunity for public comment on 

the initial submittal and meaningful 

engagement with stakeholders, 

including vulnerable communities, 

during the time in preparation of the 

initial submittal and the plans for 

engagement during development of the 

final plan. 

(b) You must submit an initial 

submittal allowed in paragraph (a) of 

this section, information required under 

paragraph (c) of this section (only if a 

State elects to submit an initial 

submittal to request an extension for a 

final plan submittal), and a final State 

plan submittal according to § 60.5870. If 

a State submits an initial submittal, an 

extension for a final State plan submittal 

is considered granted and a final State 

plan submittal is due according to 

§ 60.5760(b) unless a State is notified 

within 90 days of the EPA receiving the 

initial submittal that the EPA finds the 

initial submittal does not meet the 

requirements listed in paragraph (a) of 

this section. If the EPA notifies the State 

that the initial submittal does not meet 

such requirements, the EPA will also 

notify the State that it has failed to 

submit the final plan required by 

September 6, 2016. 

(c) If an extension for submission of 

a final plan has been granted, you must 

submit a progress report by September 

6, 2017. The 2017 report must include 

the following: 

(1) A summary of the status of each 

component of the final plan, including 

an update from the 2016 initial 

submittal and a list of which final plan 

components are not complete. 

(2) A commitment to a plan approach 

(e.g., single or multi-State, rate-based or 

mass-based emission performance level, 

rate-based or mass-based emission 

standards), including draft or proposed 

legislation and/or regulations. 

(3) An updated comprehensive 

roadmap with a schedule and 

milestones for completing the final plan, 

including any updates to community 

engagement undertaken and planned. 

§ 60.5770 What schedules, performance 

periods, and compliance periods must I 

include in my plan? 

(a) The affected EGUs covered by your 

plan must meet the CO2 emission 

requirements required under § 60.5855 

for the interim period, interim steps, 

and the final reporting periods 

according to paragraph (b) of this 

section. You must also include in your 

plan compliance periods for each 

affected EGU regulated under the plan 

according to paragraphs (c) and (d) of 

this section. 

(b) Your plan must require your 

affected EGUs to achieve each CO2

emission performance rate or CO2

emission goal, as applicable, required 

under § 60.5855 over the periods 

according to paragraphs (b)(1) through 

(3) of this section. 

(1) The interim period. 

(2) Each interim step. 

(3) Each final reporting period. 

(c) The emission standards for 

affected EGUs regulated under the plan 

must include the following compliance 

periods: 

(1) For the interim period, affected 

EGUs must have emission standards 

that have compliance periods that are 

no longer than each interim step and are 

imposed for the entirety of the interim 

step either alone or in combination. 

(2) For the final period, affected EGUs 

must have emission standards that have 

compliance periods that are no longer 

than each final reporting period and are 

imposed for the entirety of the final 

reporting period either alone or in 

combination. 

(3) Compliance periods for each 

interim step and each final reporting 

period may take forms shorter than 

specified in this regulation, provided 

the schedules of compliance collectively 

end on the same schedule as each 

interim step and final reporting period. 

(d) If your plan relies upon State 

measures in lieu of or in addition to 

emission standards for affected EGUs 

regulated under the plan, then the 

performance periods must be identical 

to the compliance periods for affected 

EGUs listed in paragraphs (c)(1) through 

(3) of this section. 

§ 60.5775 What emission standards must I 

include in my plan? 

(a) Emission standard(s) for affected 

EGUs included under your plan must be 

demonstrated to be quantifiable, 

verifiable, non-duplicative, permanent, 

and enforceable with respect to each 

affected EGU. The plan submittal must 

include the methods by which each 

emission standard meets each of the 

following requirements in paragraphs 

(b) through (f) of this section. 

(b) An affected EGU’s emission 

standard is quantifiable if it can be 

reliably measured in a manner that can 

be replicated. 

(c) An affected EGU’s emission 

standard is verifiable if adequate 

monitoring, recordkeeping and 

reporting requirements are in place to 

enable the State and the Administrator 

to independently evaluate, measure, and 

verify compliance with the emission 

standard. 

(d) An affected EGU’s emission 

standard is non-duplicative with respect 

to a State plan if it is not already 

incorporated as an emission standard in 

another State plan unless incorporated 

in multi-State plan. 

(e) An affected EGU’s emission 

standard is permanent if the emission 

standard must be met for each 

compliance period, 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 are 

specified; 

(2) Compliance requirements are 

clearly defined; 

(3) The affected EGUs responsible for 

compliance and liable for violations can 

be identified; 

(4) Each compliance activity or 

measure is enforceable as a practical 

matter; and 

(5) The Administrator, the State, and 

third parties maintain the ability to 

enforce against violations (including if 

an affected EGU does not meet its 

emission standard based on its 


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emissions, its allowances if it is subject 

to a mass-based emission standard, or 

its ERCs if it is subject to a rate-based 

emission standard) and secure 

appropriate corrective actions, in the 

case of the Administrator pursuant to 

CAA sections 113(a)–(h), in the case of 

a State, pursuant to its plan, State law 

or CAA section 304, as applicable, and 

in the case of third parties, pursuant to 

CAA section 304. 

§ 60.5780 What State measures may I rely 

upon in support of my plan? 

You may rely upon State measures in 

support of your plan that are not 

emission standard(s) on affected EGUs, 

provided those State measures meet the 

requirements in paragraph (a) of this 

section. 

(a) Each State measure is quantifiable, 

verifiable, non-duplicative, permanent, 

and enforceable with respect to each 

affected entity (e.g., entities other than 

affected EGUs with no federally 

enforceable obligations under a State 

plan), and your plan supporting 

materials include the methods by which 

each State measure meets each of the 

following requirements in paragraphs 

(a)(1) through (5) of this section. 

(1) A State measure is quantifiable 

with respect to an affected entity if it 

can be reliably measured in a manner 

that can be replicated. 

(2) A State measure is verifiable with 

respect to an affected entity if adequate 

monitoring, recordkeeping and 

reporting requirements are in place to 

enable the State to independently 

evaluate, measure, and verify 

compliance with the State measure. 

(3) A State measure is non-duplicative 

with respect to an affected entity if it is 

not already incorporated as a State 

measure or an emission standard in 

another State plan or State plan 

supporting material unless incorporated 

in a multi-State plan. 

(4) A State measure is permanent with 

respect to an affected entity if the State 

measure must be met for at least each 

compliance period, or unless either it is 

replaced by another State measure in an 

approved plan revision, or the State 

demonstrates in an approved plan 

revision that the emission reductions 

from the State measure are no longer 

necessary for the State’s affected EGUs 

to meet their mass-based CO2 emission 

goal. 

(5) A State measure is enforceable 

against an affected entity if: 

(i) A technically accurate limitation or 

requirement and the time period for the 

limitation or requirement are specified; 

(ii) Compliance requirements are 

clearly defined; 

(iii) The affected entities responsible 

for compliance and liable for violations 

can be identified; 

(iv) Each compliance activity or 

measure is enforceable as a practical 

matter; and 

(v) The State maintains the ability to 

enforce violations and secure 

appropriate corrective actions. 

(b) [Reserved] 

§ 60.5785 What is the procedure for 

revising my plan? 

(a) EPA-approved plans can be 

revised only with approval by the 

Administrator. The Administrator will 

approve a plan revision if it is 

satisfactory with respect to the 

applicable requirements of this subpart 

and any applicable requirements of 

subpart B of this part, including the 

requirement in § 60.5745(a)(3) to 

demonstrate achievement of the CO2

emission performance rates or CO2

emission goals in § 60.5855. If one (or 

more) of the elements of the plan set in 

§ 60.5740 require revision with respect 

to achieving the CO2 emission 

performance rates or CO2 emission goals 

in § 60.5855, a request must be 

submitted to the Administrator 

indicating the proposed revisions to the 

plan to ensure the CO2 emission 

performance rates or CO2 emission goals 

are met. In addition, the following 

provisions in paragraphs (b) through (d) 

of this section may apply. 

(b) You may submit revisions to a 

plan to adjust CO2 emission goals 

according to § 60.5855(d). 

(c) If your State is required to submit 

a notification according to § 60.5870(d) 

indicating a triggering of corrective 

measures as described in 

§ 60.5740(a)(2)(i) and your plan does not 

already include corrective measures to 

be implemented if triggered, you must 

revise your State plan to include 

corrective measures to be implemented. 

The corrective measures must ensure 

achievement of the CO2 emission 

performance rates or State CO2 emission 

goal. Additionally, the corrective 

measures must achieve additional CO2

emission reductions to offset any CO2

emission performance shortfall relative 

to the overall interim period or final 

period CO2 emission performance rate 

or State CO2 emission goal. The State 

plan revision submission must explain 

how the corrective measures both make 

up for the shortfall and address the State 

plan deficiency that caused the 

shortfall. The State must submit the 

revised plan and explanation to the EPA 

within 24 months after submitting the 

State report required in § 60.5870(a) 

indicating the CO2 emission 

performance deficiency in lieu of the 

requirements of § 60.28(a). The State 

must implement corrective measures 

within 6 months of the EPA’s approval 

of a plan revision adding them. The 

shortfall must be made up as 

expeditiously as practicable. 

(d) If your plan relies upon State 

measures, your backstop is triggered 

under § 60.5740(a)(3)(i), and your State 

measures plan backstop does not 

include a mechanism to make up the 

shortfall, you must revise your backstop 

emission standards to make up the 

shortfall. The shortfall must be made up 

as expeditiously as practicable. 

(e) Reliability Safety Valve: 

(1) In order to trigger a reliability 

safety valve, you must notify the EPA 

within 48 hours of an unforeseen, 

emergency situation that threatens 

reliability, such that your State will 

need a short-term modification of 

emission standards under a State plan 

for a specified affected EGU or EGUs. 

The EPA will consider the notification 

in § 60.5870(g)(1) to be an approved 

short-term modification to the State 

plan without needing to go through the 

full State plan revision process if the 

State provides a second notification to 

the EPA within seven days of the first 

notification. The short-term 

modification under a reliability safety 

valve allows modification to emission 

standards under the State plan for an 

affected EGU or EGUs for an initial 

period of up to 90 days. During that 

period of time, the affected EGU or 

EGUs will need to comply with the 

modified emission standards identified 

in the initial notification required under 

§ 60.5870(g)(1) or amended in the 

second notification required under 

§ 60.5870(g)(2). For the duration of the 

up to 90-day short-term modification, 

the CO2 emissions of the affected EGU 

or EGUs that exceed their obligations 

under the originally approved State plan 

will not be counted against the State’s 

CO2 emission performance rate or CO2

emission goal. The EPA reserves the 

right to review any such notification 

required under § 60.5870(g), and, in the 

event that the EPA finds such 

notification is improper, the EPA may 

disallow the short-term modification 

and affected EGUs must continue to 

operate under the approved State plan 

emission standards. As described more 

fully in § 60.5870(g)(3), at least seven 

days before the end of the initial 90-day 

reliability safety valve period, the State 

must notify the appropriate EPA 

regional office whether the reliability 

concern has been addressed and the 

affected EGU or EGUs can resume 

meeting the original emission standards 

established in the State plan prior to the 

short-term modification or whether a 


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serious, ongoing reliability issue 

necessitates the affected EGU or EGUs 

emitting beyond the amount allowed 

under the State plan. 

(2) Plan revisions submitted pursuant 

to § 60.5870(g)(3) must meet the 

requirements for State plan revisions 

under § 60.5785(a). 

§ 60.5790 What must I do to meet my plan 

obligations? 

(a) To meet your plan obligations, you 

must demonstrate that your affected 

EGUs are complying with their emission 

standards as specified in § 60.5740, and 

you must demonstrate that the emission 

standards on affected EGUs, alone or in 

conjunction with any State measures, 

are resulting in achievement of the CO2

emission performance rates or statewide 

CO2 emission goals by affected EGUs 

using the procedures in paragraphs (b) 

through (d) of this section. If your plan 

requires the use of allowances for your 

affected EGUs to comply with their 

mass-based emission standards, you 

must follow the requirements under 

paragraph (b) of this section and 

§ 60.5830. If your plan requires the use 

of ERCs for your affected EGUs to 

comply with their rate-based emission 

standards, you must follow the 

requirements under paragraphs (c) and 

(d) of this section and §§ 60.5795 

through 60.5805. 

(b) If you submit a plan that sets a 

mass-based emission trading program 

for your affected EGUs, the State plan 

must include emission standards and 

requirements that specify the allowance 

system, related compliance 

requirements and mechanisms, and the 

emission budget as appropriate. These 

requirements must include those listed 

in paragraphs (b)(1) through (5) of this 

section. 

(1) CO2 emission monitoring, 

reporting, and recordkeeping 

requirements for affected EGUs. 

(2) Requirements for State allocation 

of allowances consistent with § 60.5815. 

(3) Requirements for tracking of 

allowances, from issuance through 

submission for compliance, consistent 

with § 60.5820. 

(4) The process for affected EGUs to 

demonstrate compliance (allowance 

‘‘true-up’’ with reported CO2 emissions) 

consistent with § 60.5825. 

(5) Requirements that address 

potential increased CO2 emissions from 

new sources, beyond the emissions 

expected from new sources if affected 

EGUs were given emission standards in 

the form of the subcategory-specific CO2

emission performance rates. You may 

meet this requirement by requiring one 

of the options under paragraphs (b)(5)(i) 

through (iii) of this section. 

(i) You may include, as part of your 

plan’s supporting documentation, 

requirements enforceable as a matter of 

State law regulating CO2 emissions from 

EGUs covered by subpart TTTT of this 

part under the mass-based CO2 goal plus 

new source CO2 emission complement 

applicable to your State in Table 4 of 

this subpart. If you choose this option, 

the term ‘‘mass-based CO2 goal plus new 

source CO2 emission complement’’ shall 

apply rather than ‘‘CO2 mass-based 

goal’’ and the term ‘‘CO2 emission goal’’ 

shall include ‘‘mass-based CO2 goal plus 

new source CO2 emission complement’’ 

in these emission guidelines. 

(ii) You may include requirements in 

your State plan for emission budget 

allowance allocation methods that align 

incentives to generate to affected EGUs 

or EGUs covered by subpart TTTT of 

this part that result in the affected EGUs 

meeting the mass-based CO2 emission 

goal; 

(iii) You may submit for the EPA’s 

approval, an equivalent method which 

requires affected EGUs to meet the 

mass-based CO2 emission goal. The EPA 

will evaluate the approvability of such 

an alternative method on a case by case 

basis. 

(c) If you submit a plan that sets ratebased emission standards on your 

affected EGUs, to meet the requirements 

of § 60.5775, you must follow the 

requirements in paragraphs (c)(1) 

through (4) of this section. 

(1) You must require the owner or 

operator of each affected EGU covered 

by your plan to calculate an adjusted 

CO2 emission rate to demonstrate 

compliance with its emission standard 

by factoring stack emissions and any 

ERCs into the following equation: 

Where: 

CO2 emission rate = An affected EGU’s 

adjusted CO2 emission rate that will be 

used to determine compliance with the 

applicable CO2 emission standard. 

MCO2 = Measured CO2 mass in units of 

pounds (lbs) summed over the 

compliance period for an affected EGU. 

MWhop = Total net energy output over the 

compliance period for an affected EGU 

in units of MWh. 

MWhERC = ERC replacement generation for 

an affected EGU in units of MWh (ERCs 

are denominated in whole integers as 

specified in paragraph (d) of this 

section). 

(2) Your plan must specify that an 

ERC qualifies for the compliance 

demonstration specified in paragraph 

(c)(1) of this section if the ERC meets the 

requirements of paragraphs (c)(2)(i) 

through (iv) of this section. 

(i) An ERC must have a unique serial 

number. 

(ii) An ERC must represent one MWh 

of actual energy generated or saved with 

zero associated CO2 emissions. 

(iii) An ERC must only be issued to 

an eligible resource that meets the 

requirements of § 60.5800 or to an 

affected EGU that meets the 

requirements of § 60.5795 and must 

only be issued by a State or its State 

agent through an EPA-approved ERC 

tracking system that meets the 

requirements of § 60.5810, or by the 

EPA through an EPA-administered 

tracking system. 

(iv) An ERC must be surrendered and 

retired only once for purpose of 

compliance with this regulation through 

an EPA-approved ERC tracking system 

that meets the requirements of 

§ 60.5810, or by the EPA through an 

EPA-administered tracking system. 

(3) Your plan must specify that an 

ERC does not qualify for the compliance 

demonstration specified in paragraph 

(c)(1) of this section if it does not meet 

the requirements of paragraph (c)(2) of 

this section or if any State has used that 

same ERC for purposes of demonstrating 

achievement of a CO2 emission 

performance rate or CO2 emission goal. 

The plan must additionally include 

provisions that address requirements for 

revocation or adjustment that apply if 

an ERC issued by the State is 

subsequently found to have been 

improperly issued. 

(4) Your plan must include provisions 

either allowing for or restricting banking 

of ERCs between compliance periods for 

affected EGUs, and provisions not 

allowing any borrowing of any ERCs 

from future compliance periods by 

affected EGUs or eligible resources. 


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Emission Rate Credit Requirements 

§ 60.5795 What affected EGUs qualify for 

generation of ERCs? 

(a) For issuance of ERCs to the 

affected EGUs that generate them, the 

plan must specify the accounting 

method and process for ERC issuance. 

For plans that require that affected 

EGUs meet a rate-based CO2 emission 

goal, where all affected EGUs have 

identical emission standards, you must 

specify the accounting method listed in 

paragraph (a)(1) of this section for 

generating ERCs. For plans that require 

affected EGUs to meet the CO2 emission 

performance rates or CO2 emission goals 

where affected EGUs have emission 

standards that are not equal for all 

affected EGUs, you must specify the 

accounting methods listed in paragraphs 

(a)(1) and (2) of this section for 

generating ERCs. 

(1) You must include the calculation 

method for determining the number of 

ERCs, denominated in MWh, that may 

be generated by and issued to an 

affected EGU that is in compliance with 

its emission standard, based on the 

difference between its emission 

standard and its reported CO2 emission 

rate for the compliance period; and 

(2) You must include the calculation 

method for determining the number of 

ERCs, denominated in MWh, that may 

be issued to affected EGUs that meet the 

definition of a stationary combustion 

turbine based on the displaced 

emissions from affected EGUs not 

meeting the definition of a stationary 

combustion turbine, resulting from the 

difference between its annualized net 

energy output in MWh for the calendar 

year(s) in the compliance period and its 

net energy output in MWh for the 2012 

calendar year (January 1, 2012, through 

December 31, 2012). 

(b) Any ERCs generated through the 

method described as required by 

paragraph (a)(2) of this section must not 

be used by any affected EGUs other than 

steam generating units or IGCCs to 

demonstrate compliance as prescribed 

under § 60.5790(c)(1). 

(c) Any states in a multi-State plan 

that requires the use of ERCs for affected 

EGUs to comply with their emission 

standards must have functionally 

equivalent requirements pursuant to 

paragraphs (a)(1) and (2) of this section 

for generating ERCs. 

§ 60.5800 What other resources qualify for 

issuance of ERCs? 

(a) ERCs may only be issued for 

generation or savings produced on or 

after January 1, 2022, to a resource that 

qualifies as an eligible resource because 

it meets each of the requirements in 

paragraphs (a)(1) through (4) of this 

section. 

(1) Resources qualifying for eligibility 

only include resources that increased 

installed electrical generation nameplate 

capacity, or implemented new electrical 

savings measures, on or after January 1, 

2013. If a resource had a nameplate 

capacity uprate, ERCs may be issued 

only for the difference in generation 

between its uprated nameplate capacity 

and its nameplate capacity prior to the 

uprate. ERCs must not be issued for 

generation for an uprate that followed a 

derate that occurred on or after January 

1, 2013. A resource that is relicensed or 

receives a license extension is 

considered existing capacity and is not 

an eligible resource, unless it receives a 

capacity uprate as a result of the 

relicensing process that is reflected in 

its relicensed permit. In such a case, 

only the difference in nameplate 

capacity between its relicensed permit 

and its prior permit is eligible to be 

issued ERCs. 

(2) The resource must be connected 

to, and deliver energy to or save 

electricity on, the electric grid in the 

contiguous United States. 

(3) The resource must be located in 

either: 

(i) A State whose affected EGUs are 

subject to rate-based emission standards 

pursuant to this regulation; or 

(ii) A State with a mass-based CO2

emission goal, and the resource can 

demonstrate (e.g., through a power 

purchase agreement or contract for 

delivery) that the electricity generated is 

delivered with the intention to meet 

load in a State with affected EGUs 

which are subject to rate-based emission 

standards pursuant to this regulation, 

and was treated as a generation resource 

used to serve regional load that 

included the State whose affected EGUs 

are subject to rate-based emission 

standards. Notwithstanding any other 

provision of paragraph (a)(4) of this 

section, the only type of eligible 

resource in the State with mass-based 

emission standards is renewable 

generating technologies listed in (a)(4)(i) 

of this section. 

(4) The resource falls into one of the 

following categories of resources: 

(i) Renewable electric generating 

technologies using one of the following 

renewable energy resources: Wind, 

solar, geothermal, hydro, wave, tidal; 

(ii) Qualified biomass; 

(iii) Waste-to-energy (biogenic portion 

only); 

(iv) Nuclear power; 

(v) A non-affected combined heat and 

power (CHP) unit, including waste heat 

power; 

(vi) A demand-side EE or demandside management measure that saves 

electricity and is calculated on the basis 

of quantified ex post savings, not 

‘‘projected’’ or ‘‘claimed’’ savings; or 

(vii) A category identified in a State 

plan and approved by the EPA to 

generate ERCs. 

(b) Any resource that does not meet 

the requirements of this subpart or an 

approved State plan cannot be issued 

ERCs for use by an affected EGU with 

its compliance demonstration required 

under § 60.5790(c). 

(c) ERCs may not be issued to or for 

any of the following: 

(1) New, modified, or reconstructed 

EGUs that are subject to subpart TTTT 

of this part, except CHP units that meet 

the requirements of a CHP unit under 

paragraph (a); 

(2) EGUs that do not meet the 

applicability requirements of §§ 60.5845 

and 60.5850, except CHP units that meet 

the requirements of a CHP unit under 

paragraph (a); 

(3) Measures that reduce CO2

emissions outside the electric power 

sector, including, for example, GHG 

offset projects representing emission 

reductions that occur in the forestry and 

agriculture sectors, direct air capture, 

and crediting of CO2 emission 

reductions that occur in the 

transportation sector as a result of 

vehicle electrification; and 

(4) Any measure not approved by the 

EPA for issuance of ERCs in connection 

with a specific State plan. 

(d) You must include the appropriate 

requirements in paragraphs (d)(1) 

through (3) of this section for an 

applicable eligible resource in your 

plan. 

(1) If qualified biomass is an eligible 

resource, the plan must include a 

description of why the proposed 

feedstocks or feedstock categories 

should qualify as an approach for 

controlling increases of CO2 levels in 

the atmosphere as well as the proposed 

valuation of biogenic CO2 emissions. In 

addition, for sustainably-derived 

agricultural and forest biomass 

feedstocks, the state plan must 

adequately demonstrate that such 

feedstocks appropriately control 

increases of CO2 levels in the 

atmosphere and methods for adequately 

monitoring and verifying these 

feedstock sources and related 

sustainability practices. For all qualified 

biomass feedstocks, plans must specify 

how biogenic CO2 emissions will be 

monitored and reported, and identify 

specific EM&V, tracking and auditing 

approaches. 

(2) If waste-to-energy is an eligible 

resource, the plan must assess both the 


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capacity to strengthen existing or 

implement new waste reduction, reuse, 

recycling and composting programs, and 

measures to minimize any potential 

negative impacts of waste-to-energy 

operations on such programs. 

Additionally the plan must include a 

method for determining the proportion 

of total MWh generation from a wasteto-energy facility that is eligible for use 

in adjusting a CO2 emission rate (i.e., 

that which is generated from biogenic 

materials). 

(3) If carbon capture and utilization 

(CCU) is an eligible resource in a plan, 

the plan must include analysis 

supporting how the proposed qualifying 

CCU technology results in CO2 emission 

mitigation from affected EGUs and 

provide monitoring, reporting, and 

verification requirements to 

demonstrate the reductions. 

(e) States and areas of Indian country 

that do not have any affected EGUs, and 

other countries, may provide ERCs to 

adjust CO2 emissions provided they are 

connected to the contiguous U.S. grid 

and meet the other requirements for 

eligibility and eligible resources and the 

issuance of ERCs included in these 

emission guidelines, except that such 

States and other countries may not 

provide ERCs from resources described 

in § 60.5800(a)(4)(vi). 

§ 60.5805 What is the process for the 

issuance of ERCs? 

If your plan uses ERCs your plan must 

include the process and requirements 

for issuance of ERCs to affected EGUs 

and eligible resources set forth in 

paragraphs (a) through (f) of this section. 

(a) Eligibility application. Your plan 

must require that, to receive ERCs, the 

owner or operator must submit an 

eligibility application to you that 

demonstrates that the requirements of 

your State plan as approved by the EPA 

as meeting § 60.5795 (for an affected 

EGU) or § 60.5800 (for an eligible 

resource) are met, and, in the case of an 

eligible resource, includes at a 

minimum: 

(1) Documentation that the eligibility 

application has only been submitted to 

you, or pursuant to an EPA-approved 

multi-State collaborative approach; 

(2) An EM&V plan that meets the 

requirements of the State plan as 

approved by the EPA as meeting 

§ 60.5830; and 

(3) A verification report from an 

independent verifier that verifies the 

eligibility of the eligible resource to be 

issued an ERC and that the EM&V plan 

meets the requirements of the State plan 

as approved by the EPA of meeting 

§ 60.5805. 

(b) Registration. Your plan must 

require that any affected EGU or eligible 

resource register with an ERC tracking 

system that meets the requirements of 

§ 60.5810 prior to the issuance of ERCs, 

and your plan must specify that you 

will only register an affected EGU or 

eligible resource after you approve its 

eligibility application and determine 

that the requirements of paragraph (a) of 

this section are met. 

(c) M&V reports. For an eligible 

resource registered pursuant to 

paragraph (b) of this section, your plan 

must require that, prior to issuance of 

ERCs by you, the owner or operator 

must submit the following: 

(1) An M&V report that meets the 

requirements of your State plan as 

approved by the EPA as meeting 

§ 60.5835; and 

(2) A verification report from an 

independent verifier that verifies that 

the requirements for the M&V report are 

met. 

(e) Issuance of ERCs. Your plan must 

specify your procedure for issuance of 

ERCs based on your review of an M&V 

report and verification report, and must 

require that ERCs be issued only on the 

basis of energy actually generated or 

saved, and that only one ERC is issued 

for each verified MWh. 

(f) Tracking system. Your plan must 

require that ERCs may only be issued 

through an ERC tracking system 

approved as part of the State plan. 

(g) Error adjustment. Your plan must 

include a mechanism to adjust the 

number of ERCs issued if any are issued 

based on error (clerical, formula input 

error, etc.). 

(h) Qualification status of an eligible 

resource. Your plan must include a 

mechanism to temporarily or 

permanently revoke the qualification 

status of an eligible resource, such that 

it can no longer be issued ERCs for at 

least the duration that it does not meet 

the requirements for being issued ERCs 

in your State plan. 

(i) Qualification status of an 

independent verifier—(1) Eligibility. To 

be an independent verifier, a person 

must be approved by the State as: 

(A) An independent verifier, as 

defined by this regulation; and 

(B) Eligible to verify eligibility 

applications, EM&V plans, and/or M&V 

reports per the requirements of the 

approved State plan as meeting 

§§ 60.5830 and 60.5835 respectively. 

(2) Revocation of qualification. Your 

plan must include a mechanism to 

temporarily or permanently revoke the 

qualification status of an independent 

verifier, such that it can no longer verify 

eligibility applications, EM&V plans or 

M&V reports for at least the duration of 

the period it does not meet the 

requirements of your State plan. 

§ 60.5810 What applicable requirements 

are there for an ERC tracking system? 

(a) Your plan must include provisions 

for an ERC tracking system, if 

applicable, that meets the following 

requirements: 

(1) It electronically records the 

issuance of ERCs, transfers of ERCs 

among accounts, surrender of ERCs by 

affected EGUs as part of a compliance 

demonstration, and retirement or 

cancellation of ERCs; and 

(2) It documents and provides 

electronic, internet-based public access 

to all information that supports the 

eligibility of eligible resources and 

issuance of ERCs and functionality to 

generate reports based on such 

information, which must include, for 

each ERC, an eligibility application, 

EM&V plan, M&V reports, and 

independent verifier verification 

reports. 

(b) If approved in a State plan, an ERC 

tracking system may provide for 

transfers of ERCs to or from another ERC 

tracking system approved in a State 

plan, or provide for transfers of ERCs to 

or from an EPA-administered ERC 

tracking system used to administer a 

Federal plan. 

Mass Allocation Requirements 

§ 60.5815 What are the requirements for 

State allocation of allowances in a massbased program? 

(a) For a mass-based trading program, 

a State plan must include requirements 

for CO2 allowance allocations according 

to paragraphs (b) through (f) of this 

section. 

(b) Provisions for allocation of 

allowances for each compliance period 

prior to the beginning of the compliance 

period. 

(c) Provisions for allocation of setaside allowance, if applicable, must be 

established to ensure that the eligible 

resources must meet the same 

requirements for the ERC eligible 

resource requirements of § 60.5800, and 

the State must include eligibility 

application and verification provisions 

equivalent to those for ERCs in 

§ 60.5805 and EM&V plan and M&V 

report provisions that meet the 

requirements of § 60.5830 and 

§ 60.5835. 

(d) Provisions for adjusting 

allocations if the affected EGUs or 

eligible resources are incorrectly 

allocated CO2 allowances. 

(e) Provisions allowing for or 

restricting banking of allowances 

between compliance periods for affected 

EGUs. 


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(f) Provisions not allowing any 

borrowing of allowances from future 

compliance periods by affected EGUs. 

§ 60.5820 What are my allowance tracking 

requirements? 

(a) Your plan must include provisions 

for an allowance tracking system, if 

applicable, that meets the following 

requirements: 

(1) It electronically records the 

issuance of allowances, transfers of 

allowances among accounts, surrender 

of allowances by affected EGUs as part 

of a compliance demonstration, and 

retirement of allowances; and 

(2) It documents and provides 

electronic, internet-based public access 

to all information that supports the 

eligibility of eligible resources and 

issuance of set aside allowances, if 

applicable, and functionality to generate 

reports based on such information, 

which must include, for each set aside 

allowance, an eligibility application, 

EM&V plan, M&V reports, and 

independent verifier verification 

reports. 

(b) If approved in a State plan, an 

allowance tracking system may provide 

for transfers of allowances to or from 

another allowance tracking system 

approved in a State plan, or provide for 

transfers of allowances to or from an 

EPA-administered allowance tracking 

system used to administer a Federal 

plan. 

§ 60.5825 What is the process for affected 

EGUs to demonstrate compliance in a 

mass-based program? 

(a) A plan must require an affected 

EGU’s owners or operators to 

demonstrate compliance with emission 

standards in a mass based program by 

holding an amount of allowances not 

less than the tons of total CO2 emissions 

for such compliance period from the 

affected EGUs in the account for the 

affected EGU’s emissions in the 

allowance tracking system required 

under § 60.5820 during the applicable 

compliance period. 

(b) In a mass-based trading program a 

plan may allow multiple affected EGUs 

co-located at the same facility to 

demonstrate that they are meeting the 

applicable emission standards on a 

facility-wide basis by the owner or 

operator holding enough allowances to 

cover the CO2 emissions of all the 

affected EGUs at the facility. 

(1) If there are not enough allowances 

to cover the facility’s affected EGUs’ 

CO2 emissions then there must be 

provisions for determining the 

compliance status of each affected EGU 

located at that facility. 

(2) [Reserved] 

Evaluation Measurement and 

Verification Plans and Monitoring and 

Verification Reports 

§ 60.5830 What are the requirements for 

EM&V plans for eligible resources? 

(a) If your plan requires your affected 

EGUs to meet their emission standards 

in accordance with § 60.5790, your plan 

must include requirements that any 

EM&V plan that is submitted in 

accordance with the requirements of 

§ 60.5805, in support of the issuance of 

an ERC or set-aside allowance that can 

be used in accordance with § 60.5790, 

must meet the EM&V criteria approved 

as part of your State plan. 

(b) Your plan must require each 

EM&V plan to include identification of 

the eligible resource. 

(c) Your plan must require that an 

EM&V plan must contain specific 

criteria, as applicable to the specific 

eligible resource. 

(1) For RE resources, your plan must 

include requirements discussing how 

the generation data will be physically 

measured on a continuous basis using, 

for example, a revenue-quality meter. 

(2) For demand-side EE, your plan 

must require that each EM&V plan 

quantify and verify electricity savings 

on a retrospective (ex-post) basis using 

industry best-practice EM&V protocols 

and methods that yield accurate and 

reliable measurements of electricity 

savings. Your plan must also require 

each EM&V plan to include an 

assessment of the independent factors 

that influence the electricity savings, the 

expected life of the savings (in years), 

and a baseline that represents what 

would have happened in the absence of 

the demand-side EE activity. 

Additionally, your plan must require 

that each EM&V plan include a 

demonstration of how the industry bestpractices protocol and methods were 

applied to the specific activity, project, 

measure, or program covered in the 

EM&V plan, and include an explanation 

of why these protocols or methods were 

selected. EM&V plans must require 

eligible resources to demonstrate how 

all such best-practice approaches will be 

applied for the purposes of quantifying 

and verifying MWh results. Subsequent 

reporting of demand-side EE savings 

values must demonstrate and explain 

how the EM&V plan was followed. 

§ 60.5835 What are the requirements for 

M&V reports for eligible resources? 

(a) If your plan requires your affected 

EGUs to meet their emission standards 

in accordance with § 60.5790, your plan 

must include requirements that any 

M&V report that is submitted in 

accordance with the requirements of 

§ 60.5805, in support of the issuance of 

an ERC or set-aside allocation that can 

be used in accordance with § 60.5790, 

must meet the requirements of this 

section. 

(b) Your plan must require that each 

M&V report include the following: 

(1) For the first M&V report 

submitted, documentation that the 

energy-generating resources, energysaving measures, or practices were 

installed or implemented consistent 

with the description in the approved 

eligibility application required in 

§ 60.5805(a). 

(2) Each M&V report submitted must 

include the following: 

(i) Identification of the time period 

covered by the M&V report; 

(ii) A description of how relevant 

quantification methods, protocols, 

guidelines, and guidance specified in 

the EM&V plan were applied during the 

reporting period to generate the 

quantified MWh of generation or MWh 

of energy savings; 

(iii) Documentation (including data) 

of the energy generation and/or energy 

savings from any activity, project, 

measure, resource, or program 

addressed in the EM&V plan, quantified 

and verified in MWh for the period 

covered by the M&V report, in 

accordance with its EM&V plan, and 

based on ex-post energy generation or 

savings; and 

(iv) Documentation of any change in 

the energy generation or savings 

capability of the eligible resource from 

the description of the resource in the 

approved eligibility application during 

the period covered by the M&V report 

and the date on which the change 

occurred, and/or demonstration that the 

eligible resource continued to meet the 

requirements of § 60.5800. 

Applicability of Plans to Affected EGUs 

§ 60.5840 Does this subpart directly affect 

EGU owners or operators in my State? 

(a) This subpart does not directly 

affect EGU owners or operators in your 

State. However, affected EGU owners or 

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 a final 

plan to implement and enforce the 

emission guidelines contained in this 

subpart, or an initial submittal for 

which an extension to submit a final 

plan can be granted, by September 6, 

2016, or the EPA disapproves a final 

plan, the EPA will implement and 

enforce a Federal plan, as provided in 

§ 60.5720, applicable to each affected 

EGU within the State that commenced 


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construction on or before January 8, 

2014. 

§ 60.5845 What affected EGUs must I 

address in my State plan? 

(a) The EGUs that must be addressed 

by your plan are any affected steam 

generating unit, IGCC, or stationary 

combustion turbine that commenced 

construction on or before January 8, 

2014. 

(b) An affected EGU is a steam 

generating unit, IGCC, or stationary 

combustion turbine that meets the 

relevant applicability conditions 

specified in paragraph (b)(1) through (3) 

of this section, as applicable, except as 

provided in § 60.5850. 

(1) Serves a generator or generators 

connected to a utility power distribution 

system with a nameplate capacity 

greater than 25 MW-net (i.e., capable of 

selling greater than 25 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. 

§ 60.5850 What EGUs are excluded from 

being affected EGUs? 

EGUs that are excluded from being 

affected EGUs are: 

(a) EGUs that are subject to subpart 

TTTT of this part as a result of 

commencing construction after the 

subpart TTTT applicability date; 

(b) Steam generating units and IGCCs 

that are, 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; 

(c) Non-fossil units (i.e., units that are 

capable of combusting 50 percent or 

more non-fossil fuel) that have always 

historically limited the use of fossil 

fuels to 10 percent or less of the annual 

capacity factor or are subject to a 

federally enforceable permit limiting 

fossil fuel use to 10 percent or less of 

the annual capacity factor; 

(d) Stationary combustion turbines 

not capable of combusting natural gas 

(e.g., not connected to a natural gas 

pipeline); 

(e) EGUs that are combined heat and 

power units that have always 

historically limited, or are subject to a 

federally enforceable permit limiting, 

annual net-electric sales to a utility 

distribution system to no more than the 

greater of either 219,000 MWh or the 

product of the design efficiency and the 

potential electric output; 

(f) 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; 

(g) EGUs that are a municipal waste 

combustor unit that is subject to subpart 

Eb of this part; and 

(h) EGUs that are a commercial or 

industrial solid waste incineration unit 

that is subject to subpart CCCC of this 

part. 

§ 60.5855 What are the CO2 emission 

performance rates for affected EGUs? 

(a) You must require, in your plan, 

emission standards on affected EGUs to 

meet the CO2 emission performance 

rates listed in Table 1 of this subpart 

except as provided in paragraph (b) of 

this section. In addition, you must set 

CO2 emission performance rates for the 

interim steps, according to paragraph 

(a)(1) of this section, except as provided 

in paragraph (b) of this section. 

(1) You must set CO2 emission 

performance rates for your affected 

EGUs to meet during the interim step 

periods on average and as applicable for 

the two subcategories of affected EGUs. 

(2) [Reserved] 

(b) You may elect to require your 

affected EGUs to meet emission 

standards that differ from the CO2

emission performance rates listed in 

Table 1 of this subpart, provided that 

you demonstrate that the affected EGUs 

in your State will collectively meet their 

CO2 emission performance rate by 

achieving statewide emission goals that 

are equivalent and no less stringent than 

the CO2 emission performance rates 

listed in Table 1, and provided that your 

equivalent statewide CO2 emission goals 

take one of the following forms: 

(1) Average statewide rate-based CO2

emission goals listed in Table 2 of this 

subpart, except as provided in 

paragraphs (c) and (d); or 

(2) Cumulative statewide mass-based 

CO2 emission goals listed in Table 3 of 

this subpart, except as provided in 

paragraphs (c) and (d) of this section. 

(c) If your plan meets CO2 emission 

goals listed in paragraphs (b)(1) or (2) of 

this section you must develop your own 

interim step goals and final reporting 

period goal for your affected EGUs to 

meet either on average (in the case of 

rate-based goals) or cumulatively (in the 

case of mass-based goals). Additionally 

the following applies if you 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 CO2 emission goal. 

(d) Your plan’s interim period and 

final period CO2 emission goals required 

to be met pursuant to paragraph (b)(1) 

or (2) of this section, may be changed in 

the plan only according to situations 

listed in paragraphs (d)(1) through (3) of 

this section. If a situation requires a 

plan revision, you must follow the 

procedures in § 60.5785 to submit a plan 

revision. 

(1) If your plan implements CO2

emission goals, you may submit a plan 

or plan revision, allowed in § 60.5785, 

to make corrections to them, subject to 

EPA’s approval, as a result of changes in 

the inventory of affected EGUs; and 

(2) If you elect to require your affected 

EGUs to meet emission standards to 

meet mass-based CO2 emission goals in 

your plan, you may elect to incorporate, 

as a matter of state law, the mass 

emissions from EGUs that are subject to 

subpart TTTT of this part that are 

considered new affected EGUs under 

subpart TTTT of this part. 

(e) If your plan relies upon State 

measures in addition to or in lieu of 

emission standards, you must only use 

the mass-based goals allowed for in 

paragraph (b)(2) of this section to 

demonstrate that your affected EGUs are 

meeting the required emissions 

performance. 

(f) Nothing in this subpart precludes 

an affected EGU from complying with 

its emission standard or you from 

meeting your obligations under the State 

plan. 

§ 60.5860 What applicable monitoring, 

recordkeeping, and reporting requirements 

do I need to include in my plan for affected 

EGUs? 

(a) Your plan must include 

monitoring for affected EGUs that is no 

less stringent than what is described in 

(a)(1) through (8) of this section. 

(1) The owner or operator of an 

affected EGU (or group of affected EGUs 

that share a monitored common stack) 

that is required to meet rate-based or 

mass-based emission standards must 

prepare a monitoring plan in accordance 

with the applicable provisions in 

§ 75.53(g) and (h) of this chapter, unless 

such a plan is already in place under 

another program that requires CO2 mass 

emissions to be monitored and reported 

according to part 75 of this chapter. 

(2) For rate-based emission standards, 

each compliance period shall include 


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only ‘‘valid operating hours’’ in the 

compliance period, i.e., full or partial 

unit (or stack) operating hours for 

which: 

(i) ‘‘Valid data’’ (as defined in 

§ 60.5880) are obtained for all of the 

parameters used to determine the hourly 

CO2 mass emissions (lbs). For the 

purposes of this subpart, substitute data 

recorded under part 75 of this chapter 

are not considered to be valid data; and 

(ii) The corresponding hourly net 

energy output value is also valid data 

(Note: For operating hours with no 

useful output, zero is considered to be 

a valid value). 

(3) For rate-based emission standards, 

the owner or operator of an affected 

EGU must measure and report the 

hourly CO2 mass emissions (lbs) from 

each affected unit using the procedures 

in paragraphs (a)(3)(i) through (vi) of 

this section, except as otherwise 

provided in paragraph (a)(4) of this 

section. 

(i) The owner or operator of an 

affected EGU must install, certify, 

operate, maintain, and calibrate a CO2

continuous emissions monitoring 

system (CEMS) to directly measure and 

record CO2 concentrations in the 

affected EGU exhaust gases 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 of an 

affected EGU may use data from a 

certified oxygen (O2) monitor to 

calculate hourly average CO2

concentrations, in accordance with 

§ 75.10(a)(3)(iii) of this chapter. 

However, when an O2 monitor is used 

this way, it only quantifies the 

combustion CO2; therefore, if the EGU is 

equipped with emission controls that 

produce non-combustion CO2 (e.g., from 

sorbent injection), this additional CO2

must be accounted for, in accordance 

with section 3 of appendix G to part 75 

of this chapter. If CO2 concentration is 

measured on a dry basis, the owner or 

operator of the affected EGU must also 

install, certify, operate, maintain, and 

calibrate a continuous moisture 

monitoring system, according to 

§ 75.11(b) of this chapter. Alternatively, 

the owner or operator of an affected 

EGU may either use an appropriate fuelspecific default moisture value from 

§ 75.11(b) or submit a petition to the 

Administrator under § 75.66 of this 

chapter for a site-specific default 

moisture value. 

(ii) For each ‘‘valid operating hour’’ 

(as defined in paragraph (a)(2) of this 

section), calculate the hourly CO2 mass 

emission rate (tons/hr), either from 

Equation F–11 in Appendix F to part 75 

of this chapter (if CO2 concentration is 

measured on a wet basis), or by 

following the procedure in section 4.2 of 

Appendix F to part 75 of this chapter (if 

CO2 concentration is measured on a dry 

basis). 

(iii) Next, multiply each hourly CO2

mass emission rate by the EGU or stack 

operating time in hours (as defined in 

§ 72.2 of this chapter), to convert it to 

tons of CO2. Multiply the result by 2,000 

lbs/ton to convert it to lbs. 

(iv) The hourly CO2 tons/hr values 

and EGU (or stack) operating times used 

to calculate CO2 mass emissions are 

required to be recorded under § 75.57(e) 

of this chapter and must be reported 

electronically under § 75.64(a)(6), if 

required by a plan. The owner or 

operator must use these data, or 

equivalent data, to calculate the hourly 

CO2 mass emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values from paragraph 

(a)(3)(ii) of this section over the entire 

compliance period. 

(vi) For each continuous monitoring 

system used to determine the CO2 mass 

emissions from an affected EGU, the 

monitoring system must meet the 

applicable certification and quality 

assurance procedures in § 75.20 of this 

chapter and Appendices A and B to part 

75 of this chapter. 

(4) The owner or operator of an 

affected EGU that exclusively combusts 

liquid fuel and/or gaseous fuel may, as 

an alternative to complying with 

paragraph (a)(3) of this section, 

determine the hourly CO2 mass 

emissions according to paragraphs 

(a)(4)(i) through (a)(4)(vi) of this section. 

(i) Implement the applicable 

procedures in appendix D to part 75 of 

this chapter to determine hourly EGU 

heat input rates (MMBtu/hr), based on 

hourly measurements of fuel flow rate 

and periodic determinations of the gross 

calorific value (GCV) of each fuel 

combusted. The fuel flow meter(s) used 

to measure the hourly fuel flow rates 

must meet the applicable certification 

and quality-assurance requirements in 

sections 2.1.5 and 2.1.6 of appendix D 

to part 75 (except for qualifying 

commercial billing meters). The fuel 

GCV must be determined in accordance 

with section 2.2 or 2.3 of appendix D, 

as applicable. 

(ii) For each measured hourly heat 

input rate, use Equation G–4 in 

Appendix G to part 75 of this chapter to 

calculate the hourly CO2 mass emission 

rate (tons/hr). 

(iii) For each ‘‘valid operating hour’’ 

(as defined in paragraph (a)(2) of this 

section), multiply the hourly tons/hr 

CO2 mass emission rate from paragraph 

(a)(4)(ii) of this section by the EGU or 

stack operating time in hours (as 

defined in § 72.2 of this chapter), to 

convert it to tons of CO2. Then, multiply 

the result by 2,000 lbs/ton to convert it 

to lbs. 

(iv) The hourly CO2 tons/hr values 

and EGU (or stack) operating times used 

to calculate CO2 mass emissions are 

required to be recorded under § 75.57(e) 

of this chapter and must be reported 

electronically under § 75.64(a)(6), if 

required by a plan. You must use these 

data, or equivalent data, to calculate the 

hourly CO2 mass emissions. 

(v) Sum all of the hourly CO2 mass 

emissions values (lb) from paragraph 

(a)(4)(iii) of this section over the entire 

compliance period. 

(vi) The owner or operator of an 

affected EGU may determine sitespecific carbon-based F-factors (Fc) 

using Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(5) For both rate-based and massbased standards, the owner or operator 

of an affected EGU (or group of affected 

units that share a monitored common 

stack) must install, calibrate, maintain, 

and operate a sufficient number of watt 

meters to continuously measure and 

record on an hourly basis net electric 

output. Measurements must be 

performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

Further, the owner or operator of an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output. 

The owner or operator must use the 

following procedures to calculate net 

energy output, as appropriate for the 

type of affected EGU(s). 

(i) Determine Pnet the hourly net 

energy output in MWh. For rate-based 

standards, perform this calculation only 

for valid operating hours (as defined in 

paragraph (a)(2) of this section). For 

mass-based standards, perform this 

calculation for all unit (or stack) 

operating hours, i.e., full or partial 

hours in which any fuel is combusted. 

(ii) If there is no net electrical output, 

but there is mechanical or useful 

thermal output, either for a particular 

valid operating hour (for rate-based 


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applications), or for a particular 

operating hour (for mass-based 

applications), the owner or operator of 

the affected EGU must still determine 

the net energy output for that hour. 

(iii) For rate-based applications, if 

there is no (i.e., zero) gross electrical, 

mechanical, or useful thermal output for 

a particular valid operating hour, that 

hour must be used in the compliance 

determination. For hours or partial 

hours where the gross electric output is 

equal to or less than the auxiliary loads, 

net electric output shall be counted as 

zero for this calculation. 

(iv) Calculate Pnet for your affected 

EGU (or group of affected EGUs that 

share a monitored common stack) using 

the following equation. All terms in the 

equation must be expressed in units of 

MWh. To convert each hourly net 

energy output value reported under part 

75 of this chapter to MWh, multiply by 

the corresponding EGU or stack 

operating time. 

Where: 

Pnet = Net energy output of your affected EGU 

for each valid operating hour (as defined 

in 60.5860(a)(2)) in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected EGU’s integrated 

equipment that provides electricity or 

mechanical energy to the affected EGU or 

auxiliary equipment in MWh. 

(Pe)A = Electric energy used for any auxiliary 

loads in MWh. 

(Pt)PS = Useful thermal output of steam 

(measured relative to SATP conditions, 

as applicable) that is used for 

applications that do not generate 

additional electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU. 

This is calculated using the equation 

specified in paragraph (a)(5)(v) of this 

section in MWh. 

(Pt)HR = Non-steam useful thermal output 

(measured relative to SATP conditions, 

as applicable) from heat recovery that is 

used for applications other than steam 

generation or performance enhancement 

of the affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to 

SATP conditions, as applicable) from 

any integrated equipment is used for 

applications that do not generate 

additional steam, electricity, produce 

mechanical energy output, or enhance 

the performance of the affected EGU in 

MWh. 

TDF = Electric Transmission and Distribution 

Factor of 0.95 for a combined heat and 

power affected EGU where at least on an 

annual basis 20.0 percent of the total 

gross or net energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total net energy 

output consist of useful thermal output 

on a 12-operating month rolling average 

basis, or 1.0 for all other affected EGUs. 

(v) If applicable to your affected EGU 

(for example, for combined heat and 

power), you must calculate (Pt)PS using 

the following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lbs)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure (relative to 

SATP conditions or the energy in the 

condensate return line, as applicable) in 

Joules per kilogram (J/kg) (or Btu/lb). 

CF = Conversion factor of 3.6 x 109 J/MWh 

or 3.413 x 106 Btu/MWh. 

(vi) For rate-based standards, sum all 

of the values of Pnet for the valid 

operating hours (as defined in paragraph 

(a)(2) of this section), over the entire 

compliance period. Then, divide the 

total CO2 mass emissions for the valid 

operating hours from paragraph (a)(3)(v) 

or (a)(4)(v) of this section, as applicable, 

by the sum of the Pnet values for the 

valid operating hours plus any ERC 

replacement generation (as shown in 

§ 60.5790(c)), to determine the CO2

emissions rate (lb/net MWh) for the 

compliance period. 

(vii) For mass-based standards, sum 

all of the values of Pnet for all operating 

hours, over the entire compliance 

period. 

(6) In accordance with § 60.13(g), if 

two or more affected EGUs 

implementing the continuous emissions 

monitoring provisions in paragraph 

(a)(2) of this section share a common 

exhaust gas stack and are subject to the 

same emissions standard, the owner or 

operator may monitor the hourly CO2

mass emissions at the common stack in 

lieu of monitoring each EGU separately. 

If an owner or operator of an affected 

EGU chooses this option, the hourly net 

electric output for the common stack 

must be the sum of the hourly net 

electric output of the individual affected 

EGUs and the operating time must be 

expressed as ‘‘stack operating hours’’ (as 

defined in § 72.2 of this chapter). 

(7) In accordance with § 60.13(g), if 

the exhaust gases from an affected EGU 

implementing the continuous emissions 

monitoring provisions in paragraph 

(a)(2) of this section are emitted to the 

atmosphere through multiple stacks (or 

if the exhaust gases are routed to a 

common stack through multiple ducts 

and you elect to monitor in the ducts), 

the hourly CO2 mass emissions and the 

‘‘stack operating time’’ (as defined in 

§ 72.2 of this chapter) at each stack or 

duct must be monitored separately. In 

this case, the owner or operator of an 

affected EGU must determine 

compliance with an applicable 

emissions standard by summing the CO2

mass emissions measured at the 

individual stacks or ducts and dividing 

by the net energy output for the affected 

EGU. 

(8) Consistent with § 60.5775 or 

§ 60.5780, if two or more affected EGUs 

serve a common electric generator, you 

must apportion the combined hourly net 

energy output to the individual affected 

EGUs according to the fraction of the 

total steam load contributed by each 

EGU. Alternatively, if the EGUs are 

identical, you may apportion the 

combined hourly net electrical load to 

the individual EGUs according to the 

fraction of the total heat input 

contributed by each EGU. 

(b) For mass-based standards, the 

owner or operator of an affected EGU 

must determine the CO2 mass emissions 

(tons) for the compliance period as 

follows: 

(1) For each operating hour, calculate 

the hourly CO2 mass (tons) according to 

paragraph (a)(3) or (4) of this section, 

except that a complete data record is 

required, i.e., CO2 mass emissions must 

be reported for each operating hour. 

Therefore, substitute data values 

recorded under part 75 of this chapter 

for CO2 concentration, stack gas flow 

rate, stack gas moisture content, fuel 

flow rate and/or GCV shall be used in 

the calculations; and 

(2) Sum all of the hourly CO2 mass 

emissions values over the entire 

compliance period. 

(3) The owner or operator of an 

affected EGU must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 


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measure and record on an hourly basis 

net electric output. Measurements must 

be performed using 0.2 accuracy class 

electricity metering instrumentation and 

calibration procedures as specified 

under ANSI Standards No. C12.20. 

Further, the owner or operator of an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output 

(Pnet). The owner or operator must 

calculate net energy output according to 

paragraphs (a)(5)(i)(A) and (B) of this 

section. 

(c) Your plan must require the owner 

or operator of each affected EGU 

covered by your plan to maintain the 

records, as described in paragraphs 

(b)(1) and (2) of this section, for at least 

5 years following the date of each 

compliance period, occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(1) The owner or operator of an 

affected EGU must maintain each record 

on site for at least 2 years after the date 

of each compliance period, occurrence, 

measurement, maintenance, corrective 

action, report, or record, whichever is 

latest, according to § 60.7. The owner or 

operator of an affected EGU may 

maintain the records off site and 

electronically for the remaining year(s). 

(2) The owner or operator of an 

affected EGU must keep all of the 

following records, in a form suitable and 

readily available for expeditious review: 

(i) All documents, data files, and 

calculations and methods used to 

demonstrate compliance with an 

affected EGU’s emission standard under 

§ 60.5775. 

(ii) Copies of all reports submitted to 

the State under paragraph (c) of this 

section. 

(iii) Data that are required to be 

recorded by 40 CFR part 75 subpart F. 

(iv) Data with respect to any ERCs 

generated by the affected EGU or used 

by the affected EGU in its compliance 

demonstration including the 

information in paragraphs (c)(2)(iv)(A) 

and (B) of this section. 

(A) All documents related to any 

ERCs used in a compliance 

demonstration, including each 

eligibility application, EM&V plan, M&V 

report, and independent verifier 

verification report associated with the 

issuance of each specific ERC. 

(B) All records and reports relating to 

the surrender and retirement of ERCs for 

compliance with this regulation, 

including the date each individual ERC 

with a unique serial identification 

number was surrendered and/or retired. 

(d) Your plan must require the owner 

or operator of an affected EGU covered 

by your plan to include in a report 

submitted to you at the end of each 

compliance period the information in 

paragraphs (d)(1) through (5) of this 

section. 

(1) Owners or operators of an affected 

EGU must include in the report all 

hourly CO2 emissions, for each affected 

EGU (or group of affected EGUs that 

share a monitored common stack). 

(2) For rate-based standards, each 

report must include: 

(i) The hourly CO2 mass emission rate 

values (tons/hr) and unit (or stack) 

operating times, (as monitored and 

reported according to part 75 of this 

chapter), for each valid operating hour 

in the compliance period; 

(ii) The net electric output and the net 

energy output (Pnet) values for each valid 

operating hour in the compliance 

period; 

(iii) The calculated CO2 mass 

emissions (lb) for each valid operating 

hour in the compliance period; 

(iv) The sum of the hourly net energy 

output values and the sum of the hourly 

CO2 mass emissions values, for all of the 

valid operating hours in the compliance 

period; 

(v) ERC replacement generation (if 

any), properly justified (see paragraph 

(c)(5) of this section); and 

(vi) The calculated CO2 mass emission 

rate for the compliance period (lbs/net 

MWh). 

(3) For mass-based standards, each 

report must include: 

(i) The hourly CO2 mass emission rate 

value (tons/hr) and unit (or stack) 

operating time, as monitored and 

reported according to part 75 of this 

chapter, for each unit or stack operating 

hour in the compliance period; 

(ii) The calculated CO2 mass 

emissions (tons) for each unit or stack 

operating hour in the compliance 

period; 

(iii) The sum of the CO2 mass 

emissions (tons) for all of the unit or 

stack operating hours in the compliance 

period; 

(iv) The net electric output and the 

net energy output (Pnet) values for each 

unit or stack operating hour in the 

compliance period; and 

(v) The sum of the hourly net energy 

output values for all of the unit or stack 

operating hours in the compliance 

period. 

(vi) Notwithstanding the requirements 

in paragraphs (c)(3)(i) through (c)(3)(iii) 

of this section, if the compliance period 

is a discrete number of calendar years 

(e.g., one year, three years), in lieu of 

reporting the information specified in 

those paragraphs, the owner or operator 

may report: 

(A) The cumulative annual CO2 mass 

emissions (tons) for each year of the 

compliance period, derived from the 

electronic emissions report for the 

fourth calendar quarter of that year, 

submitted to EPA under § 75.64(a) of 

this chapter; and 

(B) The sum of the cumulative annual 

CO2 mass emissions values from 

paragraph (c)(3)(v)(A) of this section, if 

the compliance period includes 

multiple years. 

(4) For each affected EGU’s 

compliance period, the report must also 

include the applicable emission 

standard and demonstration that it met 

the emission standard. An owner or 

operator must also include in the report 

the affected EGU’s calculated emission 

performance as a CO2 emission rate or 

cumulative mass in units of the 

emission standard required in 

§§ 60.5790(b) through (c) and 60.5855, 

as applicable. 

(5) If the owner or operator of an 

affected EGU is complying with an 

emission standard by using ERCs, they 

must include in the report a list of all 

unique ERC serial numbers that were 

retired in the compliance period, and, 

for each ERC, the date an ERC was 

surrendered and retired and eligible 

resource identification information 

sufficient to demonstrate that it meets 

the requirements of § 60.5800 and 

qualifies to be issued ERCs (including 

location, type of qualifying generation 

or savings, date commenced generating 

or saving, and date of generation or 

savings for which the ERC was issued). 

(6) If the owner or operator of an 

affected EGU is complying with an 

emission standard by using allowances, 

they must include in the report a list of 

all unique allowance serial numbers 

that were retired in the compliance 

period, and, for each allowance, the date 

an allowance was surrendered and 

retired and if the allowance was a setaside allowance the eligible resource 

identification information sufficient to 

demonstrate that it meets the 

requirements of § 60.5815(c) and 

qualifies to be issued set-aside 

allowances (including location, type of 

qualifying generation or savings, date 

commenced generating or saving, and 

date of generation or savings for which 

the allowance was issued). 

(e) The owner or operator of an 

affected EGU must follow any 

additional requirements for monitoring, 

recordkeeping and reporting in a plan 

that are required under § 60.5745(a)(4), 

if applicable. 


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(f) If an affected EGU captures CO2 to 

meet the applicable emission limit, the 

owner or operator must report in 

accordance with the requirements of 40 

CFR part 98 subpart PP and either: 

(1) Report in accordance with the 

requirements of 40 CFR part 98 subpart 

RR, if injection occurs on-site; 

(2) Transfer the captured CO2 to an 

EGU or facility that reports in 

accordance with the requirements of 40 

CFR part 98 subpart RR, if injection 

occurs off-site; or 

(3) Transfer the captured CO2 to a 

facility that has received an innovative 

technology waiver from EPA pursuant 

to paragraph (g) of this section. 

(g) Any person may request the 

Administrator to issue a waiver of the 

requirement that captured CO2 from an 

affected EGU be transferred to a facility 

reporting under 40 CFR part 98 subpart 

RR. To receive a waiver, the applicant 

must demonstrate to the Administrator 

that its technology will store captured 

CO2 as effectively as geologic 

sequestration, and that the proposed 

technology will not cause or contribute 

to an unreasonable risk to public health, 

welfare, or safety. In making this 

determination, the Administrator shall 

consider (among other factors) operating 

history of the technology, whether the 

technology will increase emissions or 

other releases of any pollutant other 

than CO2, and permanence of the CO2

storage. The Administrator may test the 

system itself, or require the applicant to 

perform any tests considered by the 

Administrator to be necessary to show 

the technology’s effectiveness, safety, 

and ability to store captured CO2

without release. The Administrator may 

grant conditional approval of a 

technology, the approval conditioned on 

monitoring and reporting of operations. 

The Administrator may also withdraw 

approval of the waiver on evidence of 

releases of CO2 or other pollutants. The 

Administrator will provide notice to the 

public of any application under this 

provision, and provide public notice of 

any proposed action on a petition before 

the Administrator takes final action. 

Recordkeeping and Reporting 

Requirements 

§ 60.5865 What are my recordkeeping 

requirements? 

(a) You must keep records of all 

information relied upon in support of 

any demonstration of plan components, 

plan requirements, supporting 

documentation, State measures, 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 CO2 emission performance rates or 

CO2 emissions goals are being achieved. 

(b) You must keep records of all data 

submitted by the owner or operator of 

each affected EGU that is used to 

determine compliance with each 

affected EGU emissions standard or 

requirements in an approved State plan, 

consistent with the affected EGU 

requirements listed in § 60.5860. 

(c) If your State has a requirement for 

all hourly CO2 emissions and net 

generation information to be used to 

calculate compliance with an annual 

emissions standard 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 you are not required to keep 

records of information that would be in 

duplicate of paragraph (b) of this 

section. 

(d) You must keep records at a 

minimum for 10 years, for the interim 

period, and 5 years, for the final period, 

from the date the record is used to 

determine compliance with an 

emissions standard, plan requirement, 

CO2 emission performance rate or CO2

emissions goal. Each record must be in 

a form suitable and readily available for 

expeditious review. 

§ 60.5870 What are my reporting and 

notification requirements? 

(a) In lieu of the annual report 

required under § 60.25(e) and (f) of this 

part, you must report the information in 

paragraphs (b) through (f) of this 

section. 

(b) You must submit a report covering 

each interim step within the interim 

period and each of the final 2-calendar 

year periods due no later than July 1 of 

the year following the end of the period. 

The interim period reporting starts with 

a report covering interim step 1 due no 

later than July 1, 2025. The final period 

reports start with a biennial report 

covering the first final reporting period 

(which is due by July 1, 2032), a 

2-calendar year average of emissions or 

cumulative sum of emissions used to 

determine compliance with the final 

CO2 emission performance rate or CO2

emission goal (as applicable). The report 

must include the information in 

paragraphs (b)(1) through (4) of this 

section. 

(1) The report must include the 

emissions performance achieved by all 

affected EGUs during the reporting 

period, consistent with the plan 

approach according to § 60.5745(a), and 

identification of whether each affected 

EGU is in compliance with its emission 

standard and whether the collective of 

all affected EGUs covered by the State 

are on schedule to meet the applicable 

CO2 emission performance rate or 

emission goal during the performance 

periods and compliance periods, as 

specified in the plan. 

(2) The report must include a 

comparison of the CO2 emission 

performance rate or CO2 emission goal 

identified in the State plan for the 

applicable interim step period versus 

the actual average, cumulative, or 

adjusted CO2 emission performance (as 

applicable) achieved by all affected 

EGUs. 

(i) For interim step 3, you do not need 

to include a comparison between the 

applicable interim step 3 CO2 emission 

performance rate or emission goal; you 

must only submit the average, 

cumulative or adjusted CO2 emission 

performance (as applicable) of your 

affected EGUs during that period in 

units of your applicable CO2 emission 

performance rate or emission goal. 

(3) The report must include all other 

required information, as specified in 

your State plan according to 

§ 60.5740(a)(5). 

(4) If applicable, the report must 

include a program review that your 

State has conducted that addresses all 

aspects of the administration of the 

State plan and overall program, 

including State evaluations and 

regulatory decisions regarding eligibility 

applications for ERC resources and M&V 

reports (and associated EM&V 

activities), and State issuance of ERCs. 

The program review must assess 

whether the program is being 

administered properly in accordance 

with the approved plan, whether 

reported annual MWh of generation and 

savings from qualified ERC resources 

are being properly quantified, verified, 

and reported in accordance with 

approved EM&V plans, and whether 

appropriate records are being 

maintained. The program review must 

also address determination of the 

eligibility of verifiers by the State and 

the conduct of independent verifiers, 

including the quality of verifier reviews. 

(c) If your plan relies upon State 

measures, in lieu of or in addition to 

emission standards, then you must 

submit an annual report to the EPA in 

addition to the reports required under 

paragraph (b) of this section for the 

interim period. In the final period, you 

must submit biennial reports consistent 

with those required under paragraph (b) 

of this section. The annual reports in the 

interim period must be submitted no 

later than July 1 following the end of 

each calendar year starting with 2022. 


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The annual and biennial reports must 

include the information in paragraphs 

(c)(1) and (2) of this section for the 

preceding year or two years, as 

applicable. 

(1) You must include in your report 

the status of implementation of federally 

enforceable emission standards (if 

applicable) and State measures. 

(2) You must include information 

regarding the status of the periodic 

programmatic milestones to show 

progress in program implementation. 

The programmatic milestones with 

specific dates for achievement must be 

consistent with the State measures 

included in the State plan submittal. 

(d) If your plan includes the 

requirement for emission standards on 

your affected EGUs, then you must 

submit a notification, if applicable, in 

the report required under paragraph (b) 

of this section to the EPA if your 

affected EGUs trigger corrective 

measures as described in 

§ 60.5740(a)(2)(i). If corrective measures 

are required and were not previously 

submitted with your state plan, you 

must follow the requirements in 

§ 60.5785 for revising your plan to 

implement the corrective measures. 

(e) If your plan relies upon State 

measures, in lieu of or in addition to 

emission standards, than you must 

submit a notification as required under 

paragraphs (e)(1) and (2) of this section. 

(1) You must submit a notification in 

the report required under paragraph (c) 

of this section to the EPA if at the end 

of the calendar year your State did not 

meet a programmatic milestone 

included in your plan submittal. This 

notification must detail the 

implementation of the backstop 

required in your plan to be fully in 

place within 18 months of the due date 

of the report required in paragraph (b) 

of this section. In addition, the 

notification must describe the steps 

taken by the State to inform the affected 

EGUs in its State that the backstop has 

been triggered. 

(2) You must submit a notification in 

the report required under paragraph (b) 

of this section to the EPA if you trigger 

the backstop as described in 

§ 60.5740(a)(3)(i). This notification must 

detail the steps that will be taken by you 

to implement the backstop so that it is 

fully in place within 18 months of the 

due date of the report required in 

paragraph (b) of this section. In 

addition, the notification must describe 

the steps taken by the State to inform 

the affected EGUs that the backstop has 

been triggered. 

(f) You must include in your 2029 

report (which is due by July 1, 2030) the 

calculation of average CO2 emissions 

rate, cumulative sum of CO2 emissions, 

or adjusted CO2 emissions rate (as 

applicable) over the interim period and 

a comparison of those values to your 

interim CO2 emission performance rate 

or emission goal. The calculated value 

must be in units consistent with the 

approach you set in your plan for the 

interim period. 

(g) The notifications listed in 

paragraphs (g)(1) through (3) of this 

section are required for the reliability 

safety valve allowed in § 60.5785(e). 

(1) As required under § 60.5785(e), 

you must submit an initial notification 

to the appropriate EPA regional office 

within 48 hours of an unforeseen, 

emergency situation. The initial 

notification must: 

(i) Include a full description, to the 

extent that it is known, of the 

emergency situation that is being 

addressed; 

(ii) Identify the affected EGU or EGUs 

that are required to run to assure 

reliability; and 

(iii) Specify the modified emission 

standards at which the identified EGU 

or EGUs will operate. 

(2) Within 7 days of the initial 

notification in § 60.5870(g)(1), the State 

must submit a second notification to the 

appropriate EPA regional office that 

documents the initial notification. If the 

State fails to submit this documentation 

on a timely basis, the EPA will notify 

the State, which must then notify the 

affected EGU(s) that they must operate 

or resume operations under the original 

approved State plan emission standards. 

This notification must include the 

following: 

(i) A full description of the reliability 

concern and why an unforeseen, 

emergency situation that threatens 

reliability requires the affected EGU or 

EGUs to operate under modified 

emission standards from those 

originally required in the State plan 

including discussion of why the 

flexibilities provided under the state’s 

plan are insufficient to address the 

concern; 

(ii) A description of how the State is 

coordinating or will coordinate with 

relevant reliability coordinators and 

planning authorities to alleviate the 

problem in an expedited manner; 

(iii) An indication of the maximum 

time that the State anticipates the 

affected EGU or EGUs will need to 

operate in a manner inconsistent with 

its or their obligations under the State’s 

approved plan; 

(iv) A written concurrence from the 

relevant reliability coordinator and/or 

planning authority confirming the 

existence of the imminent reliability 

threat and supporting the temporary 

modification request or an explanation 

of why this kind of concurrence cannot 

be provided; 

(v) The modified emission standards 

or levels that the affected EGU or EGU 

will be operating at for the remainder of 

the 90-day period if it has changed from 

the initial notification; and 

(vi) Information regarding any systemwide or other analysis of the reliability 

concern conducted by the relevant 

planning authority, if any. 

(3) At least 7 days before the end of 

the 90-day reliability safety valve 

period, the State must notify the 

appropriate EPA regional office that 

either: 

(i) The reliability concern has been 

addressed and the affected EGU or EGUs 

can resume meeting the original 

emission standards in the State plan 

approved prior to the short-term 

modification; or 

(ii) There still is a serious, ongoing 

reliability issue that necessitates the 

affected EGU or EGUs to emit beyond 

the amount allowed under the State 

plan. In this case, the State must 

provide a notification to the EPA that it 

will be submitting a State plan revision 

according to paragraph § 60.5785(a) of 

this section to address the reliability 

issue. The notification must provide the 

date by which a revised State plan will 

be submitted to EPA and documentation 

of the ongoing emergency with a written 

concurrence from the relevant reliability 

coordinator and/or planning authority 

confirming the continuing urgent need 

for the affected EGU or EGUs to operate 

beyond the requirements of the State 

plan and that there is no other 

reasonable way of addressing the 

ongoing reliability emergency but for 

the affected EGU or EGUs to operate 

under an alternative emission standard 

than originally approved under the State 

plan. After the initial 90-day period, any 

excess emissions beyond what is 

authorized in the original approved 

State plan will count against the State’s 

overall CO2 emission goal or emission 

performance rate for affected EGUs. 

§ 60.5875 How do I submit information 

required by these Emission Guidelines to 

the EPA? 

(a) You must submit to the EPA the 

information required by these emission 

guidelines following the procedures in 

paragraphs (b) through (e) of this 

section. 

(b) All negative declarations, State 

plan submittals, supporting materials 

that are part of a State plan submittal, 

any plan revisions, and all State reports 

required to be submitted to the EPA by 

the State plan must be reported through 

EPA’s State Plan Electronic Collection 


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System (SPeCS). SPeCS is a web 

accessible electronic system accessed at 

the EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). States who 

claim that a State plan submittal or 

supporting documentation includes 

confidential business information (CBI) 

must submit that information on a 

compact disc, flash drive, or other 

commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: State and Local 

Programs Group, MD C539–01, 4930 

Old Page Rd., Durham, NC 27703. 

(c) Only a submittal by the Governor 

or the Governor’s designee by an 

electronic submission through SPeCS 

shall be considered an official submittal 

to the EPA under this subpart. If the 

Governor wishes to designate another 

responsible official the authority to 

submit a State plan, the EPA must be 

notified via letter from the Governor 

prior to the September 6, 2016, deadline 

for plan submittal so that the official 

will have the ability to submit the initial 

or final plan submittal in the SPeCS. If 

the Governor has previously delegated 

authority to make CAA submittals on 

the Governor’s behalf, a State may 

submit documentation of the delegation 

in lieu of a letter from the Governor. The 

letter or documentation must identify 

the designee to whom authority is being 

designated and must include the name 

and contact information for the designee 

and also identify the State plan 

preparers who will need access to 

SPeCS. A State may also submit the 

names of the State plan preparers via a 

separate letter prior to the designation 

letter from the Governor in order to 

expedite the State plan administrative 

process. Required contact information 

for the designee and preparers includes 

the person’s title, organization and 

email address. 

(d) The submission of the information 

by the authorized official must be in a 

non-editable format. In addition to the 

non-editable version all plan 

components designated as federally 

enforceable must also be submitted in 

an editable version. Following initial 

plan approval, States must provide the 

EPA with an editable copy of any 

submitted revision to existing approved 

federally enforceable plan components, 

including State plan backstop measures. 

The editable copy of any such submitted 

plan revision must indicate the changes 

made at the State level, if any, to the 

existing approved federally enforceable 

plan components, using a mechanism 

such as redline/strikethrough. These 

changes are not part of the State plan 

until formal approval by EPA. 

(e) You must provide the EPA with 

non-editable and editable copies of any 

submitted revision to existing approved 

federally enforceable plan components, 

including State plan backstop measures. 

The editable copy of any such submitted 

plan revision must indicate the changes 

made at the State level, if any, to the 

existing approved federally enforceable 

plan components, using a mechanism 

such as redline/strikethrough. These 

changes are not part of the State plan 

until formal approval by EPA. 

Definitions 

§ 60.5880 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subparts A, B, and TTTT, of this part. 

Adjusted CO2 Emission Rate Means 

(1) For an affected EGU, the reported 

CO2 emission rate of an affected EGU, 

adjusted as described in § 60.5790(c)(1) 

to reflect any ERCs used by an affected 

EGU to demonstrate compliance with its 

CO2 emission standards; or 

(2) For a State (or states in a multistate plan) calculating a collective CO2

emission rate achieved under the plan, 

the actual CO2 emission rate during a 

plan reporting period of the affected 

EGUs subject to the rate specified in the 

plan, adjusted by the ERCs used for 

compliance by those EGUs (total CO2

mass divided by the sum of the total 

MWh and ERCs). 

Affected electric generating unit or 

Affected EGU means a steam generating 

unit, integrated gasification combined 

cycle (IGCC), or stationary combustion 

turbine that meets the relevant 

applicability conditions in section 

§ 60.5845. 

Allowance means an authorization for 

each specified unit of actual CO2

emitted from an affected EGU or a 

facility during a specified period. 

Allowance system means a control 

program under which the owner or 

operator of each affected EGU is 

required to hold an allowance for each 

specified unit of CO2 emitted from that 

affected EGU or facility during a 

specified period and which limits the 

total amount of such allowances for a 

specified period and allows the transfer 

of such allowances. 

Annual capacity factor means the 

ratio between the actual heat input to an 

EGU during a calendar year and the 

potential heat input to the EGU had it 

been operated for 8,760 hours during a 

calendar year at the base load rating. 

Base load rating means the maximum 

amount of heat input (fuel) that an EGU 

can combust on a steady-state basis, as 

determined by the physical design and 

characteristics of the EGU at ISO 

conditions. For a stationary combustion 

turbine, base load rating includes the 

heat input from duct burners. 

Biomass means biologically based 

material that is living or dead (e.g., 

trees, crops, grasses, tree litter, roots) 

above and below ground, and available 

on a renewable or recurring basis. 

Materials that are biologically based 

include non-fossilized, biodegradable 

organic material originating from 

modern or contemporarily grown plants, 

animals, or microorganisms (including 

plants, products, byproducts and 

residues from agriculture, forestry, and 

related activities and industries, as well 

as the non-fossilized and biodegradable 

organic fractions of industrial and 

municipal wastes, including gases and 

liquids recovered from the 

decomposition of non-fossilized and 

biodegradable organic material). 

CO2 emission goal means a statewide 

rate-based CO2 emission goal or massbased CO2 emission goal specified in 

§ 60.5855. 

Combined cycle unit means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit to generate 

additional electricity. 

Combined heat and power unit or 

CHP unit, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that uses a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy source. 

Compliance period means a discrete 

time period for an affected EGU to 

comply with either an emission 

standard or State measure. 

Demand-side energy efficiency project 

means an installed piece of equipment 

or system, a modification of an existing 

piece of equipment or system, or a 

strategy intended to affect consumer 

electricity-use behavior, that results in a 

reduction in electricity use (in MWh) at 

an end-use facility, premises, or 

equipment connected to the electricity 

grid. 

Derate means a decrease in the 

available capacity of an electric 

generating unit, due to a system or 

equipment modification or to 

discounting a portion of a generating 

unit’s capacity for planning purposes. 

Eligible resource means a resource 

that meets the requirements of 

§ 60.5800(a). 


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Emission Rate Credit or ERC means a 

tradable compliance instrument that 

meets the requirements of § 60.5790(c). 

EM&V plan means a plan that meets 

the requirements of § 60.5830. 

ERC tracking system means a system 

for the issuance, surrender and 

retirement of ERCs that meets the 

requirements of § 60.5810. 

Final period means the period that 

begins on January 1, 2030, and 

continues thereafter. The final period is 

comprised of final reporting periods, 

each of which may be no longer than 

two calendar years (with a calendar year 

beginning on January 1 and ending on 

December 31). 

Final reporting period means an 

increment of plan performance within 

the final period, with each final 

reporting period being no longer than 

two calendar years (with a calendar year 

beginning on January 1 and ending on 

December 31), with the first final 

reporting period in the final period 

beginning on January 1, 2030, and 

ending no later than December 31, 2031. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid 

fuel, liquid fuel, or gaseous fuel derived 

from such material for the purpose of 

creating useful heat. 

Heat recovery steam generating unit 

(HRSG) means a unit in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Independent verifier means a person 

(including any individual, corporation, 

partnership, or association) who has the 

appropriate technical and other 

qualifications to provide verification 

reports. The independent verifier must 

not have, or have had, any direct or 

indirect financial or other interest in the 

subject of its verification report or ERCs 

that could impact their impartiality in 

performing verification services. 

Integrated gasification combined 

cycle facility or IGCC means a combined 

cycle facility that is designed to burn 

fuels containing 50 percent (by heat 

input) or more solid-derived fuel not 

meeting the definition of natural gas 

plus any integrated equipment that 

provides electricity or useful thermal 

output to either the affected facility or 

auxiliary equipment. The Administrator 

may waive the 50 percent solid-derived 

fuel requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

Interim period means the period of 

eight calendar years from January 1, 

2022, to December 31, 2029. The interim 

period is composed three interim steps, 

interim step 1, interim step 2, and 

interim step 3. 

Interim step means an increment of 

plan performance within the interim 

period. 

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 (15 

°C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

M&V report means a report that meets 

the requirements of § 60.5835. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected facility, generate 

electricity and/or thermal output, or to 

enhance the performance of the affected 

facility. Mechanical energy measured in 

horsepower hour must be converted into 

MWh by multiplying it by 745.7 then 

dividing by 1,000,000. 

Nameplate capacity means, starting 

from the initial installation, the 

maximum electrical generating output 

that a generator, prime mover, or other 

electric power production equipment 

under specific conditions designated by 

the manufacturer is capable of 

producing (in MWe, rounded to the 

nearest tenth) on a steady-state basis 

and during continuous operation (when 

not restricted by seasonal or other 

deratings) as of such installation as 

specified by the manufacturer of the 

equipment, or starting from the 

completion of any subsequent physical 

change resulting in an increase in the 

maximum electrical generating output 

that the equipment is capable of 

producing on a steady-state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount (in MWe, rounded to the nearest 

tenth) as of such completion as 

specified by the person conducting the 

physical change. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous State under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: Landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

Net allowance export/import means a 

net transfer of CO2 allowances during an 

interim step, the interim period, or a 

final reporting period which represents 

the net number of CO2 allowances 

(issued by a State) that are transferred 

from the compliance accounts of 

affected EGUs in that state to the 

compliance accounts of affected EGUs 

in another State. This net transfer is 

determined based on compliance 

account holdings at the end of the plan 

performance period. Compliance 

account holdings, as used here, refer to 

the number of CO2 allowances 

surrendered for compliance during a 

plan performance period, as well as any 

remaining CO2 allowances held in a 

compliance account as of the end of a 

plan performance period. 

Net electric output means the amount 

of gross generation the generator(s) 

produce (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the electricity 

used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling 

equipment, pumps, fans, pollution 

control equipment, other electricity 

needs, and transformer losses as 

measured at the transmission side of the 

step up transformer (e.g., the point of 

sale). 

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). 

Programmatic milestone means the 

implementation of measures necessary 

for plan progress, including specific 

dates associated with such 


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implementation. Prior to January 1, 

2022, programmatic milestones are 

applicable to all state plan approaches 

and measures. Subsequent to January 1, 

2022, programmatic milestones are 

applicable to state measures. 

Qualified biomass means a biomass 

feedstock that is demonstrated as a 

method to control increases of CO2

levels in the atmosphere. 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25 °C, 77 °F)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

State agent means an entity acting on 

behalf of the State, with the legal 

authority of the State. 

State measures means measures that 

are adopted, implemented, and enforced 

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 sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self-propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly it is considered a 

steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Uprate means an increase in available 

electric generating unit power capacity 

due to a system or equipment 

modification. 

Useful thermal output means the 

thermal energy made available for use in 

any heating application (e.g., steam 

delivered to an industrial process for a 

heating application, including thermal 

cooling applications) that is not used for 

electric generation, mechanical output 

at the affected EGU, to directly enhance 

the performance of the affected EGU 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output), or to supply 

energy to a pollution control device at 

the affected EGU. Useful thermal output 

for affected EGU(s) with no condensate 

return (or other thermal energy input to 

the affected EGU(s)) or where measuring 

the energy in the condensate (or other 

thermal energy input to the affected 

EGU(s)) would not meaningfully impact 

the emission rate calculation is 

measured against the energy in the 

thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy 

in the condensate return (or other 

thermal energy input to the affected 

EGU) must measure the energy in the 

condensate and subtract that energy 

relative to SATP conditions from the 

measured thermal output. 

Valid data means quality-assured data 

generated by continuous monitoring 

systems that are installed, operated, and 

maintained according to part 75 of this 

chapter. For CEMS, the initial 

certification requirements in § 75.20 of 

this chapter and appendix A to part 75 

of this chapter must be met before 

quality-assured data are reported under 

this subpart; for on-going 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 qualityassured data are reported under this 

subpart (except for qualifying 

commercial billing meters under section 

2.1.4.2 of appendix D), and for on-going 

quality assurance, the provisions in 

section 2.1.6 of appendix D to part 75 

of this chapter apply (except for 

qualifying commercial billing meters). 

Waste-to-Energy means a process or 

unit (e.g., solid waste incineration unit) 

that recovers energy from the 

conversion or combustion of waste 

stream materials, such as municipal 

solid waste, to generate electricity and/ 

or heat. 

TABLE 1 TO SUBPART UUUU OF PART 60—CO2 EMISSION PERFORMANCE RATES

[Pounds of CO2 per net MWh] 

Affected EGU Interim rate Final rate 

Steam generating unit or integrated gasification combined cycle (IGCC) .............................................................. 1,534 1,305 

Stationary combustion turbine ................................................................................................................................. 832 771 

TABLE 2 TO SUBPART UUUU OF PART 60—STATEWIDE RATE-BASED CO2 EMISSION GOALS

[Pounds of CO2 per net MWh] 

State Interim emission goal Final emission goal 

Alabama ................................................................................................................................... 1,157 1,018 

Arizona ..................................................................................................................................... 1,173 1,031 

Arkansas .................................................................................................................................. 1,304 1,130 

California .................................................................................................................................. 907 828 

Colorado .................................................................................................................................. 1,362 1,174 

Connecticut .............................................................................................................................. 852 786 

Delaware .................................................................................................................................. 1,023 916 

Florida ...................................................................................................................................... 1,026 919 

Georgia .................................................................................................................................... 1,198 1,049 

Idaho ........................................................................................................................................ 832 771 

Illinois ....................................................................................................................................... 1,456 1,245 


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TABLE 2 TO SUBPART UUUU OF PART 60—STATEWIDE RATE-BASED CO2 EMISSION GOALS—Continued 

[Pounds of CO2 per net MWh] 

State Interim emission goal Final emission goal 

Indiana ..................................................................................................................................... 1,451 1,242 

Iowa ......................................................................................................................................... 1,505 1,283 

Kansas ..................................................................................................................................... 1,519 1,293 

Kentucky .................................................................................................................................. 1,509 1,286 

Lands of the Fort Mojave Tribe ............................................................................................... 832 771 

Lands of the Navajo Nation ..................................................................................................... 1,534 1,305 

Lands of the Uintah and Ouray Reservation ........................................................................... 1,534 1,305

Louisiana .................................................................................................................................. 1,293 1,121 

Maine ....................................................................................................................................... 842 779 

Maryland .................................................................................................................................. 1,510 1,287 

Massachusetts ......................................................................................................................... 902 824 

Michigan ................................................................................................................................... 1,355 1,169 

Minnesota ................................................................................................................................ 1,414 1,213 

Mississippi ................................................................................................................................ 1,061 945 

Missouri .................................................................................................................................... 1,490 1,272 

Montana ................................................................................................................................... 1,534 1,305 

Nebraska .................................................................................................................................. 1,522 1,296 

Nevada ..................................................................................................................................... 942 855 

New Hampshire ....................................................................................................................... 947 858 

New Jersey .............................................................................................................................. 885 812 

New Mexico ............................................................................................................................. 1,325 1,146 

New York ................................................................................................................................. 1,025 918 

North Carolina .......................................................................................................................... 1,311 1,136 

North Dakota ............................................................................................................................ 1,534 1,305 

Ohio ......................................................................................................................................... 1,383 1,190 

Oklahoma ................................................................................................................................. 1,223 1,068 

Oregon ..................................................................................................................................... 964 871 

Pennsylvania ............................................................................................................................ 1,258 1,095 

Rhode Island ............................................................................................................................ 832 771 

South Carolina ......................................................................................................................... 1,338 1,156 

South Dakota ........................................................................................................................... 1,352 1,167 

Tennessee ............................................................................................................................... 1,411 1,211 

Texas ....................................................................................................................................... 1,188 1,042 

Utah ......................................................................................................................................... 1,368 1,179 

Virginia ..................................................................................................................................... 1,047 934 

Washington .............................................................................................................................. 1,111 983 

West Virginia ............................................................................................................................ 1,534 1,305 

Wisconsin ................................................................................................................................. 1,364 1,176 

Wyoming .................................................................................................................................. 1,526 1,299 

TABLE 3 TO SUBPART UUUU OF PART 60—STATEWIDE MASS-BASED CO2 EMISSION GOALS

[Short tons of CO2] 

State Interim emission goal 

(2022–2029) 

Final emission goals 

(2 year blocks starting 

with 2030–2031) 

Alabama ................................................................................................................................... 497,682,304 113,760,948 

Arizona ..................................................................................................................................... 264,495,976 60,341,500 

Arkansas .................................................................................................................................. 269,466,064 60,645,264 

California .................................................................................................................................. 408,216,600 96,820,240 

Colorado .................................................................................................................................. 267,103,064 59,800,794 

Connecticut .............................................................................................................................. 57,902,920 13,883,046 

Delaware .................................................................................................................................. 40,502,952 9,423,650 

Florida ...................................................................................................................................... 903,877,832 210,189,408 

Georgia .................................................................................................................................... 407,408,672 92,693,692 

Idaho ........................................................................................................................................ 12,401,136 2,985,712 

Illinois ....................................................................................................................................... 598,407,008 132,954,314 

Indiana ..................................................................................................................................... 684,936,520 152,227,670 

Iowa ......................................................................................................................................... 226,035,288 50,036,272 

Kansas ..................................................................................................................................... 198,874,664 43,981,652 

Kentucky .................................................................................................................................. 570,502,416 126,252,242 

Lands of the Fort Mojave Tribe ............................................................................................... 4,888,824 1,177,038 

Lands of the Navajo Nation ..................................................................................................... 196,462,344 43,401,174 

Lands of the Uintah and Ouray Reservation ........................................................................... 20,491,560 4,526,862 

Louisiana .................................................................................................................................. 314,482,512 70,854,046 

Maine ....................................................................................................................................... 17,265,472 4,147,884 

Maryland .................................................................................................................................. 129,675,168 28,695,256 

Massachusetts ......................................................................................................................... 101,981,416 24,209,494 

Michigan ................................................................................................................................... 424,457,200 95,088,128 


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TABLE 3 TO SUBPART UUUU OF PART 60—STATEWIDE MASS-BASED CO2 EMISSION GOALS—Continued 

[Short tons of CO2] 

State Interim emission goal 

(2022–2029) 

Final emission goals 

(2 year blocks starting 

with 2030–2031) 

Minnesota ................................................................................................................................ 203,468,736 45,356,736 

Missouri .................................................................................................................................... 500,555,464 110,925,768 

Mississippi ................................................................................................................................ 218,706,504 50,608,674 

Montana ................................................................................................................................... 102,330,640 22,606,214 

Nebraska .................................................................................................................................. 165,292,128 36,545,478 

Nevada ..................................................................................................................................... 114,752,736 27,047,168 

New Hampshire ....................................................................................................................... 33,947,936 7,995,158 

New Jersey .............................................................................................................................. 139,411,048 33,199,490 

New Mexico ............................................................................................................................. 110,524,488 24,825,204 

New York ................................................................................................................................. 268,762,632 62,514,858 

North Carolina .......................................................................................................................... 455,888,200 102,532,468 

North Dakota ............................................................................................................................ 189,062,568 41,766,464 

Ohio ......................................................................................................................................... 660,212,104 147,539,612 

Oklahoma ................................................................................................................................. 356,882,656 80,976,398 

Oregon ..................................................................................................................................... 69,145,312 16,237,308 

Pennsylvania ............................................................................................................................ 794,646,616 179,644,616 

Rhode Island ............................................................................................................................ 29,259,080 7,044,450 

South Carolina ......................................................................................................................... 231,756,984 51,997,936 

South Dakota ........................................................................................................................... 31,591,600 7,078,962 

Tennessee ............................................................................................................................... 254,278,880 56,696,792 

Texas ....................................................................................................................................... 1,664,726,728 379,177,684 

Utah ......................................................................................................................................... 212,531,040 47,556,386 

Virginia ..................................................................................................................................... 236,640,576 54,866,222 

Washington .............................................................................................................................. 93,437,656 21,478,344 

West Virginia ............................................................................................................................ 464,664,712 102,650,684 

Wisconsin ................................................................................................................................. 250,066,848 55,973,976 

Wyoming .................................................................................................................................. 286,240,416 63,268,824 

TABLE 4 TO SUBPART UUUU OF PART 60— STATEWIDE MASS-BASED CO2 GOALS PLUS NEW SOURCE CO2 EMISSION

COMPLEMENT

[Short tons of CO2] 

State Interim emission goal 

(2022–2029) 

Final emission goals 

(2 year blocks starting 

with 2030–2031) 

Alabama ................................................................................................................................... 504,534,496 115,272,348 

Arizona ..................................................................................................................................... 275,895,952 64,760,392 

Arkansas .................................................................................................................................. 272,756,576 61,371,058 

California .................................................................................................................................. 430,988,824 105,647,270 

Colorado .................................................................................................................................. 277,022,392 63,645,748 

Connecticut .............................................................................................................................. 58,986,192 14,121,986 

Delaware .................................................................................................................................. 41,133,688 9,562,772 

Florida ...................................................................................................................................... 917,904,040 213,283,190 

Georgia .................................................................................................................................... 412,826,944 93,888,808 

Idaho ........................................................................................................................................ 13,155,256 3,278,026 

Illinois ....................................................................................................................................... 604,953,792 134,398,348 

Indiana ..................................................................................................................................... 692,451,256 153,885,208 

Iowa ......................................................................................................................................... 228,426,760 50,563,762 

Kansas ..................................................................................................................................... 200,960,120 44,441,644 

Kentucky .................................................................................................................................. 576,522,048 127,580,002 

Lands of the Fort Mojave Tribe ............................................................................................... 5,186,112 1,292,276 

Lands of the Navajo Nation ..................................................................................................... 202,938,832 45,911,608 

Lands of the Uintah and Ouray Reservation ........................................................................... 21,167,080 4,788,708 

Louisiana .................................................................................................................................. 318,356,976 71,708,642 

Maine ....................................................................................................................................... 17,592,128 4,219,936 

Maryland .................................................................................................................................. 131,042,600 28,996,872 

Massachusetts ......................................................................................................................... 103,782,424 24,606,744 

Michigan ................................................................................................................................... 429,446,408 96,188,604 

Minnesota ................................................................................................................................ 205,761,008 45,862,346 

Mississippi ................................................................................................................................ 221,990,024 51,332,926 

Missouri .................................................................................................................................... 505,904,560 112,105,626 

Montana ................................................................................................................................... 105,704,024 23,913,816 

Nebraska .................................................................................................................................. 167,021,320 36,926,888 

Nevada ..................................................................................................................................... 120,916,064 29,436,214 

New Hampshire ....................................................................................................................... 34,519,280 8,121,182 

New Jersey .............................................................................................................................. 141,919,248 33,752,728 

New Mexico ............................................................................................................................. 114,741,592 26,459,850 


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TABLE 4 TO SUBPART UUUU OF PART 60— STATEWIDE MASS-BASED CO2 GOALS PLUS NEW SOURCE CO2 EMISSION

COMPLEMENT—Continued 

[Short tons of CO2] 

State Interim emission goal 

(2022–2029) 

Final emission goals 

(2 year blocks starting 

with 2030–2031) 

New York ................................................................................................................................. 272,940,440 63,436,364 

North Carolina .......................................................................................................................... 461,424,928 103,753,712 

North Dakota ............................................................................................................................ 191,025,152 42,199,354 

Ohio ......................................................................................................................................... 667,812,080 149,215,950 

Oklahoma ................................................................................................................................. 361,531,056 82,001,704 

Oregon ..................................................................................................................................... 72,774,608 17,644,106 

Pennsylvania ............................................................................................................................ 804,705,296 181,863,274 

Rhode Island ............................................................................................................................ 29,819,360 7,168,032 

South Carolina ......................................................................................................................... 234,516,064 52,606,510 

South Dakota ........................................................................................................................... 31,963,696 7,161,036 

Tennessee ............................................................................................................................... 257,149,584 57,329,988 

Texas ....................................................................................................................................... 1,707,356,792 396,210,498 

Utah ......................................................................................................................................... 220,386,616 50,601,386 

Virginia ..................................................................................................................................... 240,240,880 55,660,348 

Washington .............................................................................................................................. 97,691,736 23,127,324 

West Virginia ............................................................................................................................ 469,488,232 103,714,614 

Wisconsin ................................................................................................................................. 252,985,576 56,617,764 

Wyoming .................................................................................................................................. 295,724,848 66,945,204 

[FR Doc. 2015–22842 Filed 10–22–15; 8:45 am] 

BILLING CODE 6560–50–P 


tkelley on DSK3SPTVN1PROD with BOOK 2