Joint Appendix — West Virginia, et al., Petitioners v. Environmental Protection Agency, et al.

Supreme Court briefDec 13, 2021

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Text

Nos. 20-1530, 20-1531, 20-1778, 20-1780

IN THE

Supreme Court of the United States

WEST VIRGINIA, ET AL.,

ENVIRONMENTAL PROTECTION AGENCY, ET AL.,

THE NORTH AMERICAN COAL CORPORATION,

ENVIRONMENTAL PROTECTION AGENCY, ET AL.,

WESTMORELAND MINING HOLDINGS LLC,

ENVIRONMENTAL PROTECTION AGENCY, ET AL.,

NORTH DAKOTA,

ENVIRONMENTAL PROTECTION AGENCY, ET AL.,

On Writ Of Certiorari

To The United States Court Of Appeals

For The District Of Columbia Circuit

JOINT APPENDIX (VOLUME II OF IV)

(Pages 273–866)

LINDSAY S. SEE

ELIZABETH B. PRELOGAR

Solicitor General

Counsel of Record

U.S. DEPARTMENT OF JUSTICE OFFICE OF THE W.V. ATT’Y GEN.

950 Pennsylvania Avenue, NW State Capitol Complex

Washington, DC 20530

Building 1, Room E-26

(202) 514-2217

Charleston, WV 25305

(304) 558-2021

supremectbriefs@usdoj.gov

lindsay.s.see@wvago.gov

Counsel for Federal

Respondents

Counsel for Petitioners

West Virginia, et al.

(additional counsel listed on inside cover)

PETITIONS FOR CERTIORARI FILED: APR. 29, 2021 (20-1530),

APR. 30, 2021 (20-1531), JUNE 18, 2021 (20-1778 & 20-1780)

CERTIORARI GRANTED: OCT. 29, 2021

(continued from front cover)

BETH S. BRINKMANN

Counsel of Record

COVINGTON & BURLING LLP

850 Tenth Street, NW

Washington, DC 20001

(202) 662-5312

bbrinkmann@cov.com

Counsel for Power Company

Respondents

YAAKOV M. ROTH

Counsel of Record

JONES DAY

51 Louisiana Ave., NW

Washington, DC 20001

(202) 879-3939

yroth@jonesday.com

Counsel for Petitioner

North American Coal

Corporation

SEAN H. DONAHUE

Counsel of Record

ANDREW M. GROSSMAN

Counsel of Record

DONAHUE, GOLDBERG &

BAKER & HOSTETLER LLP

LITTLETON

1008 Pennsylvania Ave., SE

1050 Connecticut Ave., NW

Washington, DC 20003

Washington, DC 20036

(202) 277-7085

(202) 861-1697

sean@donahuegoldberg.com

agrossman@bakerlaw.com

Counsel for Non-Governmental Counsel for Petitioner

Organization & Trade

Westmoreland Mining

Association Respondents

Holdings LLC

BARBARA D. UNDERWOOD

PAUL M. SEBY

Special Assistant

Solicitor General

Attorney General

Counsel of Record

OFFICE OF THE ATT’Y GEN.

GREENBERG TRAURIG, LLP

28 Liberty Street

1144 15th Street, Suite 3300

New York, NY 10005

Denver, CO 80202

(212) 416-8016

barbara.underwood@ag.ny.gov (303) 572-6500

sebyp@gtlaw.com

Counsel for Respondents

Counsel for Petitioner State

New York, States and

of North Dakota

Municipalities

(additional counsel listed on next page)

(continued from inside cover)

ELBERT LIN

Counsel of Record

HUNTON ANDREWS KURTH LLP

951 E. Byrd Street, E. Tower

Richmond, VA 23219

(804) 788-7202

elin@huntonak.com

Counsel for Respondent

America’s Power

EMILY C. SCHILLING

Counsel of Record

HOLLAND & HART LLP

901 K Street NW, Suite 850

Washington, DC 20001

(202) 393-6500

ecschilling@hollandhart.com

Counsel for Respondent Basin

Electric Power Cooperative

MISHA TSEYTLIN

Counsel of Record

TROUTMAN PEPPER HAMILTON

SANDERS LLP

227 W. Monroe St., Suite 3900

Chicago, IL 60606

(608) 999-1240

misha.tseytlin@troutman.com

Counsel for Respondent

National Mining Association

TABLE OF CONTENTS

Page

VOLUME I

Docket Entries,

American Lung Association, et al. v.

EPA, et al., No. 19-1140 (D.C. Cir.) ................... 1

Opinion of the United States Court of Appeals

for the District of Columbia Circuit

(Jan. 19, 2021) .................................................. 53

Respondents’ Motion for a Partial Stay of

Issuance of the Mandate (Feb. 12, 2021) ....... 256

Order of the United States Court of Appeals

for the District of Columbia Circuit

Granting the Motion for a Partial Stay of

Issuance of the Mandate (Feb. 22, 2021) ....... 270

Formal Partial Mandate of the United States

Court of Appeals for the District of

Columbia Circuit (Mar. 5, 2021) .................... 272

VOLUME II

Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric

Utility Generating Units,

80 Fed. Reg. 64,662 (Oct. 23, 2015) ............... 273

VOLUME III

Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric

Utility Generating Units, 80 Fed. Reg.

64,662 (Oct. 23, 2015) (cont.) ......................... 867

TABLE OF CONTENTS

(continued)

Page

VOLUME IV

Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric

Utility Generating Units, 80 Fed. Reg.

64,662 (Oct. 23, 2015) (cont.) ....................... 1445

EPA, Regulatory Impact Analysis for the

Repeal of the Clean Power Plan, and

the Emission Guidelines for Greenhouse

Gas Emissions from Existing Electric

Utility Generating Units (June 2019)

(Excerpted).................................................... 1669

Repeal of the Clean Power Plan; Emission

Guidelines for Greenhouse Gas

Emissions From Existing Electric Utility

Generating Units; Revisions to Emission

Guidelines Implementing Regulations,

84 Fed. Reg. 32,520 (July 8, 2019) ............... 1725

273

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 fuel-fired EGUs—fossil

fuel-fired electric utility steam generating units and

stationary combustion turbines; state-specific 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.

274

ADDRESSES: Docket. The EPA has established a

docket for this action under Docket No. EPA-HQ-OAR2013-0602. 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

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

275

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;

address:

vasu.amy@epa.gov

Mr. Colin

Boswell,

Measurements Policy Group (D243-05), Sector Policies

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

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

facsimile number (919) 541-4991; email address:

boswell.colin@epa.gov.

SUPPLEMENTARY INFORMATION:

Acronyms. A number of acronyms and chemical

symbols are used in this preamble. While this may not

be an exhaustive list, to ease the reading of this

preamble and for reference purposes, the following

terms and acronyms are defined as follows:

ACEEE American Council for an Energy-Efficient

Economy

AEO Annual Energy Outlook

AFL-CIO American Federation of Labor and Congress

of Industrial Organizations

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

276

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

277

lb CO2/MWh Pounds of CO2 per Megawatt-hour

LBNL Lawrence Berkeley National Laboratory

MMBtu Million British Thermal Units

MW Megawatt

MWh Megawatt-hour

NAAQS National Ambient Air Quality Standards

NAICS North

System

American

Industry

Classification

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

Advancement Act

Technology

Transfer

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

and

278

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:

General Information

A. Executive Summary

B. Organization and Approach for This Final

Rule

II. Background

A. Climate Change Impacts From GHG

Emissions

B. GHG Emissions From Fossil Fuel-Fired

EGUs

C. The Utility Power Sector

D. Challenges in Controlling Carbon Dioxide

Emissions

279

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

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

280

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

281

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

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

Considerations

Environmental

Justice

A. Proximity Analysis

B. Community Engagement in State Plan

Development

C. Providing Communities With Access to

Additional Resources

D. Federal Programs and Resources Available to

Communities

E. Multi-Pollutant Planning and Co-Pollutants

F. Assessing Impacts of State Plan

Implementation

282

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

283

H. Executive Order 13211, Actions Concerning

Regulations That Significantly Affect Energy

Supply, Distribution, or Use

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

284

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 fuel-fired EGUs—fossil

fuel-fired electric steam generating units and

stationary combustion turbines—that expresses the

“best system of emissions reduction . . . adequately

demonstrated” (BSER) for CO2 from the power sector.1

1 Under CAA section 111(d), pursuant to 40 CFR 60.22(b)(5),

states must establish, in their state plans, emission standards

that reflect the degree of emission limitation achievable through

the application of the ‘‘best system of emission reduction’’ that,

taking into account the cost of achieving such reduction and any

non-air quality health and environmental impacts and energy

requirements, the Administrator determines has been

285

The EPA is also establishing state-specific rate-based

and mass-based goals that reflect the subcategoryspecific 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

CO2

emission

performance rates—either directly by means of

source-specific

emission

standards

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

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

286

do not have affected EGUs, they will not be required

to submit a state plan. Because the EPA does not

possess all of the information or analytical tools

needed to quantify the BSER for the two noncontiguous states with otherwise affected EGUs

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

otherwise affected EGUs (Guam and Puerto Rico),

these emission guidelines do not apply to those areas,

and those areas will not be required to submit state

plans on the schedule required by this final action.

The emission standards in a state’s plan may

incorporate the subcategory-specific CO2 emission

performance rates set by 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 subcategoryspecific 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

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.

287

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.

288

2. Purpose of This Rule

The purpose of this rule is to protect human health

and the environment by reducing CO2 emissions from

fossil fuel-fired power plants in the U.S. These plants

are by far the largest domestic stationary source of

emissions of CO2, the most prevalent of the group of

air pollutant GHGs that the EPA has determined

endangers public health and welfare through its

contribution to climate change. This rule establishes

for the first time emission guidelines for existing

power plants. These guidelines will lead to significant

reductions in CO2 emissions, result in cleaner

generation from the existing power plant fleet, and

support continued investments by the industry in

cleaner power generation to ensure reliable, affordable

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,

289

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 states in this regard is especially

important because CAA section 111(d) relies on the

well-established state-EPA partnership to accomplish

the required CO2 emission reductions. States will

have the flexibility to choose from a range of plan

approaches and measures, including numerous

measures beyond those considered in setting the CO2

emission performance rates, and this final rule allows

and encourages states to adopt the most effective set

of solutions for their circumstances, taking account of

cost and other considerations. This rulemaking, which

will be implemented through the state-EPA

partnership, is a significant step that will reduce air

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

the same time, the final rule greatly facilitates

flexibility for EGUs by establishing a basis for states

to set trading-based emission standards and

compliance strategies. The rule establishes this basis

by including both uniform emission performance rates

290

for the two subcategories of sources and also statespecific 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 wellbeing 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.,

The President’s Climate Action Plan, June 2013.

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

t27sclimateactionplan.pdf.

291

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.

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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 lower-emitting 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

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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 emissions. States, in their CAA

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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

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companies of various sizes that own and operate fossil

fuel-fired EGUs, including vertically integrated

companies in regulated markets, independent power

producers, rural cooperatives and municipally-owned

utilities, some of which are likely to have more direct

access than others to certain types of GHG emission

reduction opportunities, but all of which have a wide

range of opportunities to achieve reductions or acquire

clean generation.

Again, with features that facilitate mass-based

and/or interstate trading, the final guidelines also

empower affected EGUs to pursue a broad range of

choices for compliance and for integrating compliance

action with the full range of their investments and

operations.

c. Main elements. This final rule comprises three

main elements: (1) Two subcategory-specific CO2

emission performance rates resulting from application

of the BSER to the two subcategories of affected EGUs;

(2) state-specific CO2 goals, expressed as both

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

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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

297

structure and generation mix) also differ. Therefore,

as in the proposal, each state will have the latitude to

design a program to meet source-category specific

emission performance rates or the equivalent

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

reflects its particular circumstances and energy and

environmental policy objectives. Each state can do so

on its own, or a state can collaborate with other states

and/or tribal governments on multi-state plans, or

states can include in their plans the trading tools that

EGUs can use to realize additional opportunities for

cost savings while continuing to operate across the

interstate system through which electricity is

produced. A state would also have the option of

adopting 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

4 The

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

model rules for existing fossil fuel-fired EGUs are being

published concurrently with this final rule.

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steps for planning and then for demonstration of CO2

reductions that will ensure that progress is being

made in achieving CO2 emission reductions. States

will be able to choose from a wide range of emission

reduction measures, including measures that are not

part of the BSER, as discussed in detail in section

VIII.G of this preamble.

d. Determining the BSER. In issuing this final

rulemaking, the EPA is implementing statutory

provisions that have been in place since Congress first

enacted the CAA in 1970 and that have been

implemented pursuant to regulations promulgated in

1975 and followed in numerous subsequent CAA

section 111 rulemakings. These requirements call on

the EPA to develop emission guidelines that reflect the

EPA’s determination of the “best system of emission

reduction . . . adequately demonstrated” for states to

follow in formulating plans to establish emission

standards to implement the BSER.

As the EPA has done in making BSER

determinations in previous CAA section 111

rulemakings, for this final BSER determination, the

agency considered the types of strategies that states

and owners and operators of EGUs are already

employing to reduce the covered pollutant (in this case,

CO2) from affected sources (in this case, fossil fuelfired EGUs).5

5 The final emission guidelines for landfill gas emissions from

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

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

respectively), provide an example, as the guidelines allow either

of two approaches for controlling landfill gas—by recovering the

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

destroying the organic content of the gas on the premises using a

299

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 loweremitting existing natural gas combined cycle units for

generation from higher-emitting 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

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.

300

emissions trading.6 At the same time, and as we noted

in the proposal, there are numerous other measures

available to reduce CO2 emissions from affected EGUs,

and our determination of the BSER does not

necessitate the use of the three building blocks to their

maximum extent, or even at all. The building blocks

and the BSER determination are described in detail in

section V of this preamble.

e. CO2 state-level goals and subcategory-specific

emission performance rates.

(1) Final CO2 goals and emission performance rates.

In this action, the EPA is establishing CO2 emission

performance rates for two subcategories of affected

EGUs—fossil fuel-fired electric utility steam

generating units and stationary combustion turbines.

For fossil fuel-fired steam generating units, we are

finalizing an emission performance rate of

1,305 lb CO2/MWh.

For stationary combustion

turbines, we are finalizing an emission performance

rate of 771 lb CO2/MWh. As we did at proposal, for

each state, we are also promulgating rate-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

6 The EPA notes that, in quantifying the emission reductions

that are achievable through application of the BSER, some

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

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

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

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

apply to all affected EGUs.

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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 mass-based 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

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expected reductions, as long as the state’s interim goal

is met over the 8-year period.

State plans.7

In this action, the EPA is establishing final

guidelines for states to follow in developing,

submitting and implementing their plans.

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

7 The

CAA section 111(d) emission guidelines apply to the

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

Indian tribe that has been approved by the EPA pursuant to

40 CFR 49.9 as eligible to develop and implement a CAA

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

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

to represent them. Because Vermont and the District of

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

submit a state plan. Because the EPA 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.

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aggregate, or in combination with other measures

undertaken by the state, represent the equivalent of

the subcategory-specific CO2 emission performance

rates. This final rule includes several options for state

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

comments we received.

First, in the final rule, states may establish

emission standards for their affected EGUs that

mirror the uniform emission performance rates for the

two subcategories of sources included in this final rule.

They may also pursue alternative approaches that

adopt emission standards that meet the uniform

emission performance rates, or emission standards

that meet either the rate-based goal promulgated for

the state or the alternative mass-based goal

promulgated for the state. It is for the purpose of

providing states with these choices that the EPA is

providing state-specific rate-based and mass-based

goals equivalent to the emission performance rates

that the EPA is establishing for the two subcategories

of fossil fuel-fired EGUs. A detailed explanation of

rate- and mass-based goals is provided in section VII

of this preamble and in a TSD.8 In developing its plan,

each state and eligible tribe electing to submit a plan

will need to choose whether its plan will result in the

achievement of the CO2 emission performance rates,

statewide rate-based goals, or statewide mass-based

goals by the affected EGUs.

The second major set of options provided in the final

rule includes the types of measures states may rely on

8 The CO2 Emission Performance Rate and Goal Computation

TSD for the CPP Final Rule, available in the docket for this

rulemaking.

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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 stateenforceable 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

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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

multi-year period, through a variety of reduction

strategies, using state-specific or multi-state

approaches that can be achieved on either a rate or

mass basis. They also address several key policy

considerations that states can be expected to

contemplate in developing their plans.

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

independent notice and comment rulemaking.

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State plan approaches and plan guidelines are

explained further in section VIII of this preamble.

(2) State

criteria.

plan

components

and

approvability

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

components:

plans

must

include

the

following

•

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 goal11

10 40 CFR 60.23.

11 A

state that chooses to set emission standards that are

identical to the emission performance rates for both the interim

period and in 2030 and beyond need not identify interim state

goals nor include a separate demonstration that its plan will

achieve the state goals.

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• Monitoring, reporting and

requirements for affected EGUs

• State

requirements

recordkeeping

and

recordkeeping

reporting

• 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

each

affected

EGU;

identification of federally enforceable emission

standards for the affected EGUs; and monitoring,

recordkeeping and reporting requirements.

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• Demonstrations that each emission standard

will result in reductions that are quantifiable, nonduplicative, permanent, verifiable, and enforceable.

State plan submittals using the state measures

approach must also include:

• Identification

each

affected

EGU;

identification of federally enforceable emission

standards for affected EGUs (if applicable);

identification of backstop of federally enforceable

emission standards; and monitoring, recordkeeping

and reporting requirements.

• Identification of each state measure and

demonstration that each state measure will result in

reductions that are quantifiable, non-duplicative,

permanent, verifiable, and enforceable.

In addition to these requirements, each state plan

must follow the EPA implementing regulations at

40 CFR 60.23.

(3) Timing and process for state plan submittal and

review.

Because of the compelling need for actions to begin

the steps necessary to reduce GHG emissions from

EGUs, the EPA proposed that states submit their

plans within 13 months of the date of this final rule

and that reductions begin in 2020. In light of the

comments received and in order to provide maximum

flexibility to states while still taking timely action to

reduce CO2 emissions, in this final rule the EPA is

allowing for a 2-year extension until September 6,

2018, for both individual and multi-state plans, to

provide a total of 3 years for states to submit a final

plan if an extension is received. Specifically, the final

rule requires each state to submit a final plan by

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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

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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 90day period. Further, states participating in a multistate 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

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approval or disapproval of plans from the four-month

period provided in the EPA implementing regulations

to a twelve-month period. This timeline will provide

adequate time for the EPA to review plans and follow

notice-and-comment rulemaking procedures to ensure

an opportunity for public comment.

The EPA,

especially through our regional offices, will be

available to work with states as they develop their

plans, in order to make review of submitted plans

more straightforward and to 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

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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

statewide interim period goals, on average, that a

state may establish over the 8-year period from 2022–

2029. The CAA section 111(d) plan must include those

specific requirements. Affected EGUs must also

achieve the final CO2 performance rates or the

equivalent statewide goal by 2030 and maintain that

level subsequently.

This approach reflects

adjustments to the timeframe over which reductions

must be achieved that mirror the determination of the

final BSER, which incorporates the phasing in of the

BSER measures in keeping with the achievability of

those measures.

The agency believes that this

approach to timing is reasonable and appropriate, is

consistent with many of the comments we received,

and will best support the optimization of overall CO2

reductions, ratepayer affordability and electricity

system reliability.

The EPA recognizes that successfully achieving

reductions by 2022 will be facilitated by actions and

investments that yield CO2 emission reductions prior

to 2022. The final guidelines include provisions to

313

encourage early actions. States will be able to take

advantage of the impacts of early investments that

occur prior to the beginning of a plan performance

period. Under a mass-based plan, those impacts will

be reflected in reductions in the reported CO2

emissions of affected EGUs during the plan

performance period. Under a rate-based plan, states

may recognize early actions implemented after 2012

by crediting MWh of electricity generation and savings

that are achieved by those measures during the

interim and final plan performance periods. This

provision is discussed in section VIII.K of the

preamble.

In addition, to encourage early investments in RE

and demand-side EE, the EPA is establishing the

CEIP. Through this program, detailed in section

VIII.B of this preamble, states will have the

opportunity to award allowances and ERCs to

qualified providers that make early investments in RE,

as well as in demand-side EE programs implemented

in low-income communities. Those states that take

advantage of this option will be eligible to receive from

the EPA matching allowances or ERCs, up to a total

for all states that represents the equivalent of

300 million short tons of CO2 emissions.

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

314

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

considerations.

and

environmental

justice

Climate change is an environmental justice issue.

Low-income communities and communities of color

already

overburdened

pollution

are

disproportionately affected by climate change and are

less resilient than others to adapt to or recover from

climate-change impacts. While this rule will provide

broad benefits to communities across the nation by

reducing GHG emissions, it will be particularly

beneficial to populations that are disproportionately

vulnerable to the impacts of climate change and air

pollution.

Conventional pollutants emitted by power plants,

such as particulate matter (PM), SO2, hazardous air

pollutants (HAP), and nitrogen oxides (NOX), will also

be reduced as the plants reduce their carbon emissions.

These pollutants can have significant adverse local

and regional health impacts. The EPA analyzed the

communities in closest proximity to power plants and

found that they include a higher percentage of

communities of color and 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

315

“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 coalfired 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 gas-fired 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

316

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 bill-cutting benefits to

low-income communities directly, the EPA has

designed the CEIP specifically to target the incentives

it creates on investments that benefit low-income

communities.

Community

and

environmental

justice

considerations are discussed further in section IX of

this preamble.

317

(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 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

https://www.whitehouse.gov/the-press-office/2015/03/

27/fact-sheet-partnerships-opportunity-and-workforce-andeconomic-revitaliz.

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

318

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

319

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 non-compliance, provided, of course, it

obtains the needed allowances or credits in a timely

fashion.

We, nevertheless, agree with many

commenters that it is prudent to provide an electric

system reliability safety valve as a precaution.

320

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

321

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 them in

developing and implementing their plans. The EPA

will engage in formal consultations with tribal

14 www.epa.gov/cleanpowerplantoolbox.

322

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

323

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 sourcelevel emission performance rates for the source

subcategories, while retaining state-level rate- and

mass-based goals. One of the key messages conveyed

by state and utility commenters was that the final rule

should make it easier for states to adopt mass-based

programs and for utilities accustomed to operating

across broad multi-state grids to be able to avail

themselves of more “ready-made” emissions trading

regimes. The inclusion of both of these new features—

324

mass-based state goals in addition to rate-based goals,

and source-level 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

325

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

326

directly responsive to the comments we received from

the many and diverse stakeholders. The improved

guidelines reflect information and ideas that states

and utilities provided to us about both the best

approach to establishing CO2 emission reduction

requirements for EGUs and the most effective ways to

create true flexibility for states and utilities in

meeting these requirements. These final rules also

reflect the results of EPA’s robust consultation with

federal, state and regional energy agencies and

authorities, to ensure that the actions sources will

take to reduce GHG emissions will not compromise

electric system reliability or affordability of the U.S.

electricity supply. Input and assistance from FERC

and DOE have been particularly important in shaping

some provisions in these final guidelines. At the same

time, input from faith-based, community-based and

environmental justice organizations, who provided

thoughtful comments about the potential impacts of

this rule on pollution levels in overburdened

communities and economic impacts, 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

327

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

clean

generation

options,

(3) establishment of source-specific CO2 emission

performance rates that are uniform across the two

fossil fuel-fired subcategories covered in these

guidelines, as well as rate- and mass-based state goals,

to facilitate emission trading, including interstate

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

variation on the proposal’s “portfolio” option for state

plans—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

328

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

329

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 8year 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

330

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 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

331

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 subcategory-specific emission

performance rates take into account the grid-level

operations of the source category.

The final guidelines’ BSER determination also

takes into account recent reductions in the cost of

clean energy technology, as well as projections of

continuing cost reductions, and continuing increases

332

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

333

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

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 state-by-state planning could introduce

complexity into the otherwise seamless integrated

operation of affected EGUs across the multi-state

grids on which system operators, states and utilities

currently rely and intend to continue to rely.

Accordingly, they recommended that the final

guidelines facilitate emissions trading, in particular

interstate trading, which would enable EGU operators

to integrate compliance with CO2 emissions

limitations with facility and grid-level operations.

These sets of comments intersected at the point at

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

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

source level at which compliance must be achieved.

The EPA carefully considered these comments and

while we believe that the approach we took at proposal

was well-founded and reflected a number of important

considerations, we have concluded that there is a way

to address these concerns while expanding upon the

334

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 statelevel 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

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the affected EGUs in their jurisdiction. Such an

approach would lend itself to the ready establishment

of intra-state and interstate trading, with the uniform

rate-based standards of performance established for

each EGU as the basis for such trading. At the same

time, as at proposal, each state also has the option of

complying with these guidelines by adopting a plan

that takes a different approach to setting standards of

performance for its EGUs and/or by applying

complementary or alternative measures to meet the

state goal set by these guidelines—as either a rate or

a mass total.

During the outreach process and through comments,

a number of state officials and other stakeholders

expressed concern that the EPA’s approach at

proposal necessitated or represented a significant

intrusion into state-level energy policy-making,

drawing the EPA well beyond the bounds of its CAA

authority and expertise. In fact, these final guidelines

are entirely respectful of the EPA’s responsibility and

authority to regulate sources of air pollution. Instead,

by establishing and operating through uniform

performance rates for the two subcategories of sources

that can be applied by states at the individual source

level and that can readily be implemented through

emission standards that incorporate emissions trading,

these final guidelines align with the approach

Congress and the EPA have consistently taken to

regulating emissions from this and other industrial

sectors, namely setting source-level, source categorywide 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

336

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

337

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

338

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

339

investments, such as RE and demand-side EE

measures, as early as possible. We also received

comments

from

stakeholders

regarding

the

disproportionate burdens that some communities

already bear, and stating that all communities should

have equal access to the benefits of clean and

affordable energy. The EPA recognizes the validity

and importance of these perspectives, and as a result

has determined to provide a program—called the

CEIP—in which states may choose to participate.

The CEIP is designed to incentivize investment in

certain RE and demand-side EE projects that

commence construction, in the case of RE, or

commence construction, in the case of 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 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

340

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.

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• 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

342

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 8year 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.

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(9) Approaches

concerns.

for

addressing

employment

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 lower-carbon electricity

generation that the final rule reflects will cause harm

to communities that are dependent on coal. Others

had concerns about whether new jobs created as a

result of actions taken pursuant to the final rule will

allow for overall economic development. In the final

rule, the EPA encourages states, in designing their

state plans, to consider the effects of their plans on

employment and overall economic 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.

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

https://www.whitehouse.gov/the-press-office/2015/03/

27/fact-sheet-partnerships-opportunity-and-workforce-andeconomic-revitaliz.

344

(10)

Community

considerations.

and

environmental

justice

Many community leaders, environmental justice

advocates, faith-based organizations and others

commented that the benefits of this rule must be

shared broadly across society and that undue burdens

should not be imposed on low-income ratepayers. We

agree. The federal government is taking significant

steps to help low-income families and individuals gain

access to RE and demand-side EE through new

initiatives involving, for example, increasing solar

energy systems in federally subsidized homes and

supporting solar systems for others with low incomes.

The final rule ensures that bill-lowering measures

such as demand-side EE continue to be a major

compliance option. The CEIP will encourage early

investment in these types of projects as well. In

addition to carbon reduction benefits, we expect

significant near- and long-term public health benefits

in communities as conventional air pollutants are

reduced along with GHGs.

However, some

stakeholders expressed concerns about the possibility

of localized increases in emissions from some power

plants as the utility industry complies with state plans,

particular

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,

345

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 three-quarters of global GHG

emissions17 and 82 percent of U.S. GHG emissions.18

The May 2014 report of the National Climate

Assessment19 concluded that climate change impacts

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

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

global.html.

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

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

United States Environmental Protection Agency, April 15, 2015.

Available

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

usinventoryrepoft.html.

19 U.S.

Global Change Research Program, Climate Change

Impacts in the United States: The Third National Climate

346

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 climaterelated effects. Recent studies also find that certain

communities, including low-income communities and

some communities of color (more specifically,

populations

defined

jointly

ethnic/racial

characteristics and geographic location), are

disproportionately affected by certain climate change

related impacts—including heat waves, degraded air

quality, and extreme weather events—which are

associated with increased deaths, illnesses, and

economic challenges. Studies also find that climate

change poses particular threats to the health, wellbeing, and ways of life of indigenous peoples in the U.S.

b. The utility power sector. One of the strategies

of the President’s Climate Action Plan is to reduce CO2

Assessment, May 2014. Available at http://nca2014.global

change.gov/.

347

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 Memorandum21 that recognized

the importance of significant and prompt action. The

Memorandum directed the EPA to complete carbon

pollution standards, regulations or guidelines, as

appropriate, for new, modified, reconstructed and

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

leadership in moving toward a cleaner power sector.

In this action and the concurrent CAA section 111(b)

rule, the EPA is finalizing regulations to reduce GHG

emissions from fossil fuel-fired EGUs. This CAA

section 111(d) action builds on actions states and

utilities are already taking to move toward cleaner

generation of electric power.

The utility power sector is unlike other industrial

sectors. In other sectors, sources effectively operate

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

their physical operations resting in the hands of their

respective owners and operators. Pollution control

standards, which focus on each source in a non-utility

industrial source category, have reflected the

20 The

President’s Climate Action Plan, June 2013.

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

t27sclimateactionplan.pdf.

21 Presidential Memorandum—Power Sector Carbon Pollution

Standards, June 25, 2013. http://www.whitehouse.gov/thepress-office/2013/06/25/presidential-memorandum-powersector-carbon-pollution-standards.

348

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

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resources in a way that maintains electric system

reliability.

The approach we take in the final guidelines—both

in the way we defined the BSER and established the

resulting emission performance rates, and in the

ranges of options we created for states and affected

EGUs—is consistent with, and in some ways mirrors,

the interconnected, interdependent and highly

regulated nature of the utility power sector, the daily

operation of affected EGUs within this framework,

and the critical role of utilities in providing reliable,

affordable electricity at all times and in all places

within this complex, regulated system. Thus, not only

do these guidelines put a premium on providing as

much flexibility and latitude as possible for states and

utilities, they also recognize that a given EGU’s

operations are determined by the availability and use

of other generation resources to which it is physically

connected and by the collective operating regime that

integrates that individual EGU’s activity with other

resources across the grid.

In this integrated system, numerous entities have

both the capability and the responsibility to maintain

a reliable electric system. FERC, DOE, state public

utility commissions, ISOs, RTOs, other planning

authorities, and the North American Electric

Reliability Corporation (NERC), all contribute to

ensuring the reliability of the electric system in the

U.S. 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

350

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

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

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

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

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

24 Federal Power Comm’n v. Florida Power & Light Co., 404

U.S. 453, at 460 (1972) (quoting a Federal Power Commission

hearing examiner, “‘If a housewife in Atlanta on the Georgia

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

almost instantly is caused to produce some quantity of additional

electric energy which serves to maintain the balance in the

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

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

(stating that “any electricity that enters the grid immediately

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

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

Comm’n v. Southern California Edison Co., 376 U.S. 205 (1964),

the Supreme Court found that a sale for resale of electricity from

Southern California Edison to the City of Colton, which took place

solely in California, was under Federal Power Commission

jurisdiction because some of the electricity that Southern

California Edison marketed came from out of state. The Supreme

Court stated that, “‘federal jurisdiction was to follow the flow of

electric energy, an engineering and scientific, rather than a

legalistic or governmental, test.’” Id. at 210, quoting Connecticut

Light & Power Co. v. Federal Power Commission, 324 U.S. 515,

529 (1945) (emphasis omitted).

351

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 fuelfired 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

352

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

353

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 long-term planning and investment processes

already used in the utility power sector. This final rule

provides flexibility for states to build upon their

progress, and the progress of cities and towns, in

addressing GHGs, and minimizes additional

requirements for existing programs where possible. It

also allows states to pursue policies to reduce carbon

pollution that: (1) Continue to rely on a diverse set of

energy resources; (2) ensure electric system reliability;

(3) provide affordable electricity; (4) recognize

investments that states and power companies are

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

respective energy, environmental and economic needs

and goals, and those of their local communities. Thus,

25 SNL

Energy.

June 9, 2015.

Data used with permission.

Accessed on

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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 directly-emitted fine particulate matter

(PM2.5). A thorough discussion of the EPA’s analysis

is presented in Section XI.A of this preamble and in

Chapter 3 of the Regulatory Impact Analysis (RIA)

included in the docket for this rulemaking.

7. Costs and Benefits

Actions taken to comply with the final guidelines

will reduce emissions of CO2 and other air pollutants,

including SO2, NOX, and directly emitted PM2.5 from

the utility power sector. States will make the ultimate

determination as to how the emission guidelines are

implemented. Thus, all costs and benefits reported for

this action are illustrative estimates. The illustrative

costs and benefits are based upon compliance

approaches that reflect a range of measures consisting

of improved operations at EGUs, dispatching loweremitting 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

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“rate-based” illustrative plan approach and the “massbased” illustrative plan approach.

In summary, we estimate the total combined

climate benefits and health co-benefits for the

rate-based approach to be $3.5 to $4.6 billion in 2020,

$18 to $28 billion in 2025, and $34 to $54 billion in

2030 (3 percent discount rate, 2011$). Total combined

climate benefits and health co-benefits for the

mass-based approach are estimated to be $5.3 to

$8.1 billion in 2020, $19 to $29 billion in 2025, and $32

to $48 billion in 2030 (3 percent discount rate, 2011$).

A summary of the emission reductions and monetized

benefits estimated for this rule at all discount rates is

provided in Tables 15 through 22 of this preamble.

The annual compliance costs are estimated using

the Integrated Planning Model (IPM) and include

demand-side EE program and participant costs as well

as monitoring, reporting and recordkeeping costs. In

2020, total compliance costs of the final guidelines are

approximately $2.5 billion (2011$) under the

rate-based approach and $1.4 billion (2011$) under

the 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 ratebased 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)

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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 massbased 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.

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

FOR THE FINAL GUIDELINES IN 2020, 2025, AND 2030a UNDER THE RATE-BASED ILLUSTRATIVE

PLAN APPROACH

[Billions of 2011$]

Rate-based approach, 2020

3% Discount rate

7% Discount

rate

Climate benefitsb .............................................

$2.8

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

Total Compliance Costsd ................................. $2.5 ................................................................ $2.5.

Net Monetized Benefitse ................................. $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.

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Rate-based approach, 2025

Climate benefitsb .............................................

$10

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

Total Compliance Costsd ................................. $1.0 ................................................................. $1.0.

Net Monetized Benefitse ................................. $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.

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Rate-based approach, 2030

Climate benefitsb ............................................. $20

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

Total Compliance Costsd ................................. $8.4 ................................................................. $8.4.

Net Monetized Benefitse ................................. $26 to $45 ...................................................... $25 to $43.

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

Reductions in exposure to ambient NO2 and SO2.

Reductions in mercury deposition.

Ecosystem benefits associated with reductions in

emissions of NOX, SO2, PM, and mercury.

Visibility impairment.

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

b The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and

does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2

than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over many

years. The benefit estimates in this table are based on the average SCC estimated for a 3 percent discount rate,

however we emphasize the importance and value of considering the full range of SC-CO2 values. As shown in

the RIA, climate benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5

percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCFCO2 estimates are yearspecific and increase over time.

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c The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission

reductions of directly emitted PM2.5, SO2 and NOX. The range reflects the use of concentration-response

functions from different epidemiology studies. The reduction in pre-mature fatalities each year accounts for

over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles,

regardless of their chemical composition, are equally potent in causing premature mortality because the

scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.

d Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning

Model for the final guidelines and a discount rate of approximately 5%. This estimate includes monitoring,

recordkeeping, and reporting costs and demand-side EE program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent

discount rate (model average). The RIA includes combined climate and health estimates based on additional

discount rates.

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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

Climate benefitsb ...........................................

Air pollution health co-benefitsc ...................

Total Compliance Costsd ...............................

Net Monetized Benefitse ................................

Non-monetized Benefits ................................

7% Discount

rate

$3.3

$2.0 to $4.8 ..................................................... $1.8 to $4.4.

$1.4 .................................................................. $1.4.

$3.9 to $6.7 ..................................................... $3.7 to $6.3.

Non-monetized climate benefits.

Reductions in exposure to ambient NO2 and SO2.

Reductions in mercury deposition.

Ecosystem benefits associated with reductions in

emissions of NOX, SO2, PM, and mercury.

Visibility impairment.

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Mass-based approach, 2025

Climate benefitsb

Air pollution health co-benefitsc ...................

Total Compliance Costsd ...............................

Net Monetized Benefitse ...............................

Non-monetized Benefits ................................

$12

$7.1 to $17 ...................................................... $6.5 to $16.

$3.0 ................................................................. $3.0.

$16 to $26 ....................................................... $15 to $24.

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 ...........................................

$20

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

Total Compliance Costsd ............................... $5.1 ................................................................. $5.1.

Net Monetized Benefitse ............................... $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.

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

b The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and

does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SC-CO2

than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over many

years. The benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount

rate, however we emphasize the importance and value of considering the full range of SC-CO2 values. As shown

in the RIA, climate benefits are also estimated using the other three SC-CO2 estimates (model average at 2.5

percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time.

c The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission

reductions of directly emitted PM2.5, SO2 and NOX. The range reflects the use of concentration-response

functions from different epidemiology studies. The reduction in pre-mature fatalities each year accounts for

over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles,

regardless of their chemical composition, are equally potent in causing premature mortality because the

scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.

d Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning

Model for the final guidelines and a discount rate of approximately 5 percent. This estimate includes monitoring,

recordkeeping, and reporting costs and demand-side EE program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent

discount rate (model average). The RIA includes combined climate and health estimates based on additional

discount rates.

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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

26 Although CO2 is the predominant greenhouse gas released

by the power sector, electricity generating units also emit small

amounts of nitrous oxide and methane. For more detail about

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

Greenhouse Gas Reporting Program’s power sector summary,

http://www.epa.gov/ghgreporting/ghgdata/reported/powerpla

nts.html.

27 A job-year is not an individual job; rather, a job-year is the

amount of work performed by the equivalent of one full-time

individual for one year. For example, 20 job-years in 2025 may

represent 20 full-time jobs or 40 half-time jobs.

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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 rate-based

and mass-based goals. Section VIII then describes

state plan approaches and the requirements, and

flexibilities, for state plans, followed by section IX, in

which considerations for communities are described.

Interactions between this final rule and other EPA

programs and rules are discussed in section X.

Impacts of the proposed action are then described in

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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 fuel-fired 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

28 The EPA also published in the Federal Register a notice

of data availability (79 FR 64543; November 8, 2014) and a notice

on the translation of emission rate-based CO2 goals to mass-based

equivalents (79 FR 67406; November 13, 2014).

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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.

29 National Research Council, Climate Stabilization Targets,

p.3.

“Endangerment and Cause or Contribute Findings for

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

FR 66496 (Dec. 15, 2009) (“Endangerment Finding”).

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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

expected to cause more intense hurricanes and more

frequent and intense storms and heavy precipitation,

with impacts on other areas of public health, such as

the potential for increased deaths, injuries, infectious

and waterborne diseases, and stress-related disorders.

Children, the elderly, and the poor are among the most

vulnerable to these climate-related health effects.

2. Public Welfare Impacts Detailed in the 2009

Endangerment Finding

Climate change impacts touch nearly every aspect

of public welfare. Among the multiple threats caused

by human emissions of GHGs, climate changes are

expected to place large areas of the country at serious

risk of reduced water supplies, increased water

pollution, and increased occurrence of extreme events

such as floods and droughts. Coastal areas are

369

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

370

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

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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 plant-based allergens.

The NCA3 also finds that climate change, in

addition to chronic stresses such as extreme poverty,

is negatively affecting indigenous peoples’ health in

the U.S. through impacts such as

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