Vol. 79 Wednesday, 

No. 117 June 18, 2014 

Part II 

Environmental Protection Agency 

40 CFR Part 60 

Carbon Pollution Emission Guidelines for Existing Stationary Sources: 

Electric Utility Generating Units; Proposed Rule 


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34830 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2013–0602; FRL–9911–86– 

OAR] 

RIN 2060–AR33 

Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: 

Electric Utility Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: In this action, the 

Environmental Protection Agency (EPA) 

is proposing emission guidelines for 

states to follow in developing plans to 

address greenhouse gas emissions from 

existing fossil fuel-fired electric 

generating units. Specifically, the EPA 

is proposing state-specific rate-based 

goals for carbon dioxide emissions from 

the power sector, as well as guidelines 

for states to follow in developing plans 

to achieve the state-specific goals. This 

rule, as proposed, would continue 

progress already underway to reduce 

carbon dioxide emissions from existing 

fossil fuel-fired power plants in the 

United States. 

DATES: Comments on the proposed rule. 

Comments must be received on or 

before October 16, 2014. Comments on 

the information collection request. 

Under the Paperwork Reduction Act 

(PRA), since the Office of Management 

and Budget (OMB) is required to make 

a decision concerning the information 

collection request between 30 and 60 

days after June 18, 2014, a comment to 

the OMB is best assured of having its 

full effect if the OMB receives it by July 

18, 2014. 

Public Hearing. Four public hearings 

will be convened. On July 29, 2014, one 

public hearing will be held in Atlanta, 

Georgia, at the Sam Nunn Atlanta 

Federal Center Main Tower Bridge 

Conference Area, Conference Room B, 

61 Forsyth Street SW., Atlanta, GA 

30303, and one will be held in Denver, 

Colorado, at the EPA’s Region 8 

Building, 1595 Wynkoop Street, Denver, 

Colorado 80202. On July 30, 2014, a 

public hearing will be held in 

Washington, DC, at the William 

Jefferson Clinton East Building, Room 

1152, 1201 Constitution Avenue NW., 

Washington, DC 20004. On July 31, 

2014, a public hearing will be held in 

Pittsburgh, Pennsylvania at the William 

S. Moorhead Federal Building, Room 

1310, 1000 Liberty Avenue, Pittsburgh, 

Pennsylvania 15222. The hearings in 

Pittsburgh, Pennsylvania, Atlanta, 

Georgia, and Washington, DC, will 

convene at 9:00 a.m. and end at 8:00 

p.m. (Eastern Standard Time). The 

hearing in Denver, Colorado, will 

convene at 9:00 a.m. and end at 8:00 

p.m. (Mountain Daylight Time). For all 

hearings there will be a lunch break 

from 12:00 p.m. to 1:00 p.m. and a 

dinner break from 5:00 p.m. to 6:00 p.m. 

Please contact Ms. Pamela Garrett at 

919–541–7966 or at garrett.pamela@

epa.gov to register to speak at one of the 

hearings. The last day to pre-register in 

advance to speak at the hearings will be 

Friday, July 25, 2014. Additionally, 

requests to speak will be taken the day 

of the hearings at the hearing 

registration desk, although preferences 

on speaking times may not be able to be 

fulfilled. If you require the service of a 

translator or special accommodations 

such as audio description, please let us 

know at the time of registration. 

The hearings will provide interested 

parties the opportunity to present data, 

views or arguments concerning the 

proposed action. The EPA will make 

every effort to accommodate all speakers 

who arrive and register. Because these 

hearings are being held at U.S. 

government facilities, individuals 

planning to attend the hearing should be 

prepared to show valid picture 

identification to the security staff in 

order to gain access to the meeting 

room. Please note that the REAL ID Act, 

passed by Congress in 2005, established 

new requirements for entering federal 

facilities. These requirements will take 

effect July 21, 2014. If your driver’s 

license is issued by Alaska, American 

Samoa, Arizona, Kentucky, Louisiana, 

Maine, Massachusetts, Minnesota, 

Montana, New York, Oklahoma, or the 

state of Washington, you must present 

an additional form of identification to 

enter the federal buildings where the 

public hearings will be held. Acceptable 

alternative forms of identification 

include: Federal employee badges, 

passports, enhanced driver’s licenses 

and military identification cards. We 

will list any additional acceptable forms 

of identification at: http://

www2.epa.gov/cleanpowerplan/. In 

addition, you will need to obtain a 

property pass for any personal 

belongings you bring with you. Upon 

leaving the building, you will be 

required to return this property pass to 

the security desk. No large signs will be 

allowed in the building, cameras may 

only be used outside of the building and 

demonstrations will not be allowed on 

federal property for security reasons. 

The EPA may ask clarifying questions 

during the oral presentations, but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral comments 

and supporting information presented at 

the public hearing. Commenters should 

notify Ms. Garrett if they will need 

specific equipment, or if there are other 

special needs related to providing 

comments at the hearings. Verbatim 

transcripts of the hearings and written 

statements will be included in the 

docket for the rulemaking. The EPA will 

make every effort to follow the schedule 

as closely as possible on the day of the 

hearing; however, please plan for the 

hearings to run either ahead of schedule 

or behind schedule. Additionally, more 

information regarding the hearings will 

be available at: http://www2.epa.gov/

cleanpowerplan/. 

ADDRESSES: Comments. Submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2013–0602, by one of 

the following methods: 

Federal eRulemaking portal: http://

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Email: A-and-R-Docket@epa.gov. 

Include docket ID No. EPA–HQ–OAR– 

2013–0602 in the subject line of the 

message. 

Facsimile: (202) 566–9744. Include 

docket ID No. EPA–HQ–OAR–2013– 

0602 on the cover page. 

Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mail code 28221T, Attn: Docket ID No. 

EPA–HQ–OAR–2013–0602, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460. In addition, please mail a 

copy of your comments on the 

information collection provisions to the 

Office of Information and Regulatory 

Affairs, OMB, Attn: Desk Officer for the 

EPA, 725 17th St. NW., Washington, DC 

20503. 

Hand/Courier Delivery: EPA Docket 

Center, Room 3334, EPA WJC West 

Building, 1301 Constitution Ave. NW., 

Washington, DC 20004, Attn: Docket ID 

No. EPA–HQ–OAR–2013–0602. Such 

deliveries are accepted only during the 

Docket Center’s normal hours of 

operation (8:30 a.m. to 4:30 p.m., 

Monday through Friday, excluding 

federal holidays), and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: All submissions must 

include the agency name and docket ID 

number (EPA–HQ–OAR–2013–0602). 

The EPA’s policy is to include all 

comments received without change, 

including any personal information 

provided, in the public docket, available 

online at http://www.regulations.gov, 

unless the comment includes 

information claimed to be Confidential 


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Business Information (CBI) or other 

information whose disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or otherwise protected through http://

www.regulations.gov or email. Send or 

deliver information identified as CBI 

only to the following address: Mr. 

Roberto Morales, OAQPS Document 

Control Officer (C404–02), Office of Air 

Quality Planning and Standards, U.S. 

EPA, Research Triangle Park, North 

Carolina 27711, Attention Docket ID No. 

EPA–HQ–OAR–2013–0602. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information on a disk or CD–ROM that 

you mail to the EPA, mark the outside 

of the disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information you 

claim as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, 

you must submit a copy of the comment 

that does not contain the information 

claimed as CBI for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR Part 2. 

The EPA requests that you also 

submit a separate copy of your 

comments to the contact person 

identified below (see FOR FURTHER

INFORMATION CONTACT). If the comment 

includes information you consider to be 

CBI or otherwise protected, you should 

send a copy of the comment that does 

not contain the information claimed as 

CBI or otherwise protected. 

The www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption and be free of any defects or 

viruses. 

Docket: 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., CBI or other 

information whose disclosure is 

restricted by statute). Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the EPA Docket Center, William 

Jefferson Clinton Building West, 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. Visit 

the EPA Docket Center homepage at 

http://www.epa.gov/epahome/

dockets.htm for additional information 

about the EPA’s public docket. 

In addition to being available in the 

docket, an electronic copy of this 

proposed rule will be available on the 

Worldwide Web (WWW). Following 

signature, a copy of this proposed rule 

will be posted at the following address: 

http://www2.epa.gov/cleanpowerplan/. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Amy Vasu, Sector Policies and Programs 

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

Triangle Park, NC 27711; telephone 

number (919) 541–0107, facsimile 

number (919) 541–4991; email address: 

vasu.amy@epa.gov or Ms. Marguerite 

McLamb, Sector Policies and Programs 

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

Triangle Park, NC 27711; telephone 

number (919) 541–7858, facsimile 

number (919) 541–4991; email address: 

mclamb.marguerite@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 of 

Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per 

Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or 

Sequestration) 

CEMS Continuous Emissions Monitoring 

System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE Department of Energy 

ECMPS Emissions Collection and 

Monitoring Plan System 

EERS Energy Efficiency Resource Standard 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EM&V Evaluation, Measurement and 

Verification 

EO Executive Order 

EPA Environmental Protection Agency 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined 

Cycle 

IPCC Intergovernmental Panel on Climate 

Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt 

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatthour 

LBNL Lawrence Berkeley National 

Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 

MWh Megawatt-hour 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System Commissioners 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOX Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

NYSERDA New York State Energy Research 

and Development Authority 

OMB Office of Management and Budget 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission Operator 

SBA Small Business Administration 

SBC System Benefits Charge 

SCC Social Cost of Carbon 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

Tg Teragram (one trillion (10 12) 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 


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Organization of This Document. The 

information presented in this preamble 

is organized as follows: 

I. General Information 

A. Executive Summary 

B. Organization and Approach for This 

Proposed Rule 

II. Background 

A. Climate Change Impacts From GHG 

Emissions 

B. GHG Emissions From Fossil Fuel-Fired 

EGUs 

C. The Utility Power Sector 

D. Statutory and Regulatory Requirements 

III. Stakeholder Outreach and Conclusions 

A. Stakeholder Outreach 

B. Key Messages From Stakeholders 

C. Key Stakeholder Proposals 

D. Consideration of the Existing Range of 

Policies and Programs 

E. Conclusions 

IV. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

B. Summary of Legal Basis 

V. Authority To Regulate Carbon Dioxide and 

EGUs, Affected Sources, and Treatment 

of Categories 

A. Authority To Regulate Carbon Dioxide 

B. Authority To Regulate EGUs 

C. Affected Sources 

D. Implications for Tribes and U.S. 

Territories 

E. Combined Categories and Codification 

in the Code of Federal Regulations 

VI. Building Blocks for Setting State Goals 

and the Best System of Emission 

Reduction 

A. Introduction 

B. Building Blocks for Setting State Goals 

C. Detailed Discussion of Building Blocks 

and Other Options Considered 

D. Potential Combinations of the Building 

Blocks as Components of the Best 

System of Emission Reduction 

E. Determination of the Best System of 

Emission Reduction 

VII. State Goals 

A. Overview 

B. Form of Goals 

C. Proposed Goals and Computation 

Procedure 

D. State Flexibilities 

E. Alternate Goals and Other Approaches 

Considered 

F. Reliable Affordable Electricity 

VIII. State Plans 

A. Overview 

B. Approach 

C. Criteria for Approving State Plans 

D. State Plan Components 

E. Process for State Plan Submittal and 

Review 

F. State Plan Considerations 

G. Additional Factors That Can Help States 

Meet Their CO2 Emission Performance 

Goals 

H. Resources for States To Consider in 

Developing Plans 

IX. Implications for Other EPA Programs and 

Rules 

A. Implications for NSR Program 

B. Implications for Title V Program 

C. Interactions With Other EPA Rules 

X. Impacts of the Proposed Action 

A. What are the air impacts? 

B. Comparison of Building Block 

Approaches 

C. Endangered Species Act 

D. What are the energy impacts? 

E. What are the compliance costs? 

F. What are the economic and employment 

impacts? 

G. What are the benefits of the proposed 

action? 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898, Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

XII. Statutory Authority 

I. General Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

Under the authority of Clean Air Act 

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

proposing emission guidelines for states 

to follow in developing plans to address 

greenhouse gas (GHG) emissions from 

existing fossil fuel-fired electric 

generating units (EGUs). In this 

summary, we outline the proposal; 

discuss its purpose; summarize its major 

provisions, including the EPA’s 

approach to determining goals; describe 

the broad range of options available to 

states, including flexibility in timing 

requirements both for plan submission 

and compliance deadlines under those 

plans; and briefly describe the estimated 

CO2 emission reductions, costs and 

benefits expected to result from full 

implementation of the proposal. 

This rule, as proposed, would 

continue progress already underway to 

lower the carbon intensity of power 

generation in the United States (U.S.). 

Lower carbon intensity means fewer 

emissions of CO2, a potent greenhouse 

gas that contributes to climate change. 

This proposal is a significant step 

forward in the EPA and states 

partnering to reduce GHG emissions in 

the U.S. The proposal incorporates 

critical elements that reflect the 

information and views shared during 

the unprecedented effort that the EPA 

has undertaken, beginning in the 

summer of 2013, to interact directly 

with, and solicit input from, a wide 

range of states and stakeholders. This 

effort encompassed several hundred 

meetings across the country with state 

environmental and energy officials, 

public utility commissioners, system 

operators, utilities and public interest 

advocates, as well as members of the 

public. Many participants submitted 

written material and data to the EPA as 

well. 

Nationwide, by 2030, this rule would 

achieve CO2 emission reductions from 

the power sector of approximately 30 

percent from CO2 emission levels in 

2005. This goal is achievable because 

innovations in the production, 

distribution and use of electricity are 

already making the power sector more 

efficient and sustainable while 

maintaining an affordable, reliable and 

diverse energy mix. This proposed rule 

would reinforce and continue this 

progress. The EPA projects that, in 2030, 

the significant reductions in the harmful 

carbon pollution and in other air 

pollution, to which this rule would 

lead, would result in net climate and 

health benefits of $48 billion to $82 

billion. At the same time, coal and 

natural gas would remain the two 

leading sources of electricity generation 

in the U.S., with each providing more 

than 30 percent of the projected 

generation. 

Based on evidence from programs 

already being implemented by many 

states as well as input received from 

stakeholders, the agency recognizes that 

the most cost-effective system of 

emission reduction for GHG emissions 

from the power sector under CAA 

section 111(d) entails not only 

improving the efficiency of fossil fuelfired EGUs, but also addressing their 

utilization by taking advantage of 

opportunities for lower-emitting 

generation and reduced electricity 

demand across the electricity system’s 

interconnecting network or grid. 

The proposed guidelines are based on 

and would reinforce the actions already 

being taken by states and utilities to 

upgrade aging electricity infrastructure 

with 21st century technologies. The 

guidelines would ensure that these 

trends continue in ways that are 

consistent with the long-term planning 

and investment processes already used 

in this sector, to meet both region- and 

state-specific needs. The proposal 

provides flexibility for states to build 

upon their progress, and the progress of 

cities and towns, in addressing GHGs. It 

also allows states to pursue policies to 

reduce carbon pollution that: (1) 


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1 Intergovernmental Panel on Climate Change 

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

the Fourth Assessment Report of the 

Intergovernmental Panel on Climate Change,’’ 2007. 

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

ghgemissions/global.html. 2Table ES–2 ‘‘Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990–2012’’, Report EPA 430– 

R–14–003, United States Environmental Protection 

Agency, April 15, 2014. 3U.S. Global Change Research Program, Climate 

Change Impacts in the United States: The Third 

National Climate Assessment, May 2014. Available 

at http://nca2014.globalchange.gov/. 

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

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

image/president27sclimateactionplan.pdf. 

5Presidential Memorandum—Power Sector 

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

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

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

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) can be tailored 

to meet the specific energy, 

environmental and economic needs and 

goals of each state. Thus, the proposed 

guidelines would achieve meaningful 

CO2 emission reduction while 

maintaining the reliability and 

affordability of electricity in the U.S. 

a. Proposal Elements 

The proposal has two main elements: 

(1) State-specific emission rate-based 

CO2 goals and (2) guidelines for the 

development, submission and 

implementation of state plans. To set 

the state-specific CO2 goals, the EPA 

analyzed the practical and affordable 

strategies that states and utilities are 

already using to lower carbon pollution 

from the power sector. These strategies 

include improvements in efficiency at 

carbon-intensive power plants, 

programs that enhance the dispatch 

priority of, and spur private investments 

in, low emitting and renewable power 

sources, as well as programs that help 

homes and businesses use electricity 

more efficiently. In addition, in 

calculating each state’s CO2 goal, the 

EPA took into consideration the state’s 

fuel mix, its electricity market and 

numerous other factors. Thus, each 

state’s goal reflects its unique 

conditions. 

While this proposal lays out statespecific CO2 goals that each state is 

required to meet, it does not prescribe 

how a state should meet its goal. CAA 

section 111(d) creates a partnership 

between the EPA and the states under 

which the EPA sets these goals and the 

states take the lead on meeting them by 

creating plans that are consistent with 

the EPA guidelines. Each state will have 

the flexibility to design a program to 

meet its goal in a manner that reflects 

its particular circumstances and energy 

and environmental policy objectives. 

Each state can do so alone or can 

collaborate with other states on multistate plans that may provide additional 

opportunities for cost savings and 

flexibility. 

To facilitate the state planning 

process, this proposal lays out 

guidelines for the development and 

implementation of state plans. The 

proposal describes the components of a 

state plan, the latitude states have in 

developing compliance strategies, the 

flexibility they have in the timing for 

submittal of their plans and the 

flexibility they have in determining the 

schedule by which their sources must 

achieve the required CO2 reductions. 

The EPA recognizes that each state has 

differing policy considerations— 

including varying emission reduction 

opportunities and existing state 

programs and measures—and that the 

characteristics of the electricity system 

in each state (e.g., utility regulatory 

structure, generation mix and electricity 

demand) also differ. Therefore, the 

proposed guidelines provide states with 

options for meeting the state-specific 

goals established by the EPA in a 

manner that accommodates a diverse 

range of state approaches. This proposal 

also gives states considerable flexibility 

with respect to the timeframes for plan 

development and implementation, 

providing up to two or three years for 

submission of final plans and providing 

up to fifteen years for full 

implementation of all emission 

reduction measures, after the proposal is 

finalized. 

Addressing a concern raised by both 

utilities and states, the EPA is proposing 

that states could choose approaches in 

their compliance plans under which full 

responsibility for actions achieving 

reductions is not placed entirely upon 

emitting EGUs; instead, state plans 

could include measures and policies 

(e.g., demand-side energy efficiency 

programs and renewable portfolio 

standards) for which the state itself is 

responsible. Of course, individual states 

would also have the option of 

structuring programs (e.g., allowancetrading programs) under which full 

responsibility rests on the affected 

EGUs. 

The EPA believes that, using the 

flexibilities inherent in CAA section 

111(d), this proposal would result in 

significant reductions of GHG emissions 

that cause harmful climate change, 

while providing states with ample 

opportunity to design plans that use 

innovative, cost-effective strategies that 

take advantage of investments already 

being made in programs and measures 

that lower the carbon intensity of the 

power sector and reduce GHG 

emissions. 

b. Policy Context and Industry 

Conditions 

This proposal is an important step 

toward achieving the GHG emission 

reductions needed to address the 

serious threat of climate change. GHG 

pollution threatens the American public 

by leading to potentially rapid, 

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 

emissions 1 and 82 percent of U.S. GHG 

emissions.2 The May 2014 report of the 

National Climate Assessment 3

concluded that climate change impacts 

are already manifesting themselves and 

imposing losses and costs. The report 

documents increases in extreme weather 

and climate events in recent decades, 

damage and disruption to infrastructure 

and agriculture, and projects continued 

increases in impacts across a wide range 

of communities, sectors, and 

ecosystems. 

The President’s Climate Action Plan,4

issued in June 2013, recognizes that 

climate change has far-reaching harmful 

consequences and real economic costs. 

The Climate Action Plan details a broad 

array of actions to reduce GHG 

emissions that contribute to climate 

change and affect public health and the 

environment. One of the plan’s goals is 

to reduce CO2 emissions from power 

plants. This is because fossil fuel-fired 

EGUs are, by far, the largest emitters of 

GHGs, primarily in the form of CO2, 

among stationary sources in the U.S. To 

accomplish this goal, President Obama 

issued a Presidential Memorandum 5

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 modified, reconstructed 

and existing power plants by June 1, 

2015, and in doing so to build on state 

leadership in moving toward a cleaner 

power sector. 

The way that power is produced, 

distributed and used is already changing 

due to advancements in innovative 

power sector technologies and in the 

availability and cost of low carbon fuel, 

renewable energy and energy efficient 

demand-side technologies, as well as 

economic conditions. In addition, the 

average age of the coal-fired generating 

fleet is increasing. In 2025, the average 

age of the coal-fired generating fleet is 


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34834 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

6See also 40 CFR 60.22(b)(5). 

7Under CAA section 111(a)(1) and (d), the EPA 

is authorized to determine the BSER and to 

calculate the amount of emission reduction 

achievable through applying the BSER. The state is 

authorized to identify the standard or standards of 

performance that reflects that amount of emission 

reduction. In addition, the state is required to 

include in its state plan the standards of 

performance and measures to implement and 

enforce those standards. The state must submit the 

plan to the EPA, and the EPA must approve the 

plan if the standards of performance and 

implementing and enforcing measures are 

satisfactory. This is discussed in more detail in 

Sections IV, VI, VII and VIII of this preamble, as 

well as in the Legal Memorandum. 

projected to be 49 years old, and 20 

percent of units would be more than 60 

years old if they remained 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 to address the changes 

necessitated by the aging of current 

assets and infrastructure. With change 

inevitably underway between now and 

2030, a CAA section 111(d) rulemaking 

for CO2 emissions is timely and can 

inform current and ongoing decision 

making by states and utilities, as well as 

private sector business and technology 

investments. As states develop their 

plans, they will make key decisions that 

will stimulate private sector investment 

and innovation associated with 

reducing GHG emissions. We expect 

that many states will consider the 

opportunities offered for their respective 

economies as a result of this investment. 

The proposed 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. At the same time, the EPA 

believes that this proposal provides 

flexibility for states to develop plans 

that align with their unique 

circumstances, as well as their other 

environmental policy, energy and 

economic goals. All states will have the 

opportunity to shape their plans as they 

believe appropriate for meeting the 

proposed CO2 goals. This includes states 

with long-established reliance on coalfired generation, as well as states with 

a commitment to promoting renewable 

energy (including through sustainable 

forestry initiatives). It also includes 

states that are already participating in or 

implementing CO2 reduction programs, 

such as the Regional Greenhouse Gas 

Initiative (RGGI), California’s ‘‘Global 

Warming Solutions Act’’ and Colorado’s 

‘‘Clean Air, Clean Jobs Act’’. 

States would be able to rely on and 

extend programs they may already have 

created to address the power sector. 

Those states committed to Integrated 

Resource Planning (IRP) would be able 

to establish their CO2 reduction plans 

within that framework, while states 

with a more deregulated power sector 

system could develop CO2 reduction 

plans within that specific framework. 

Each state, including states without an 

existing program, would have the 

opportunity to take advantage of a wide 

variety of strategies for reducing CO2

emissions from affected EGUs. The EPA 

and other federal entities, including the 

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

Federal Energy Regulatory Commission 

(FERC) and the U.S. Department of 

Agriculture, among others, are 

committed to sharing expertise with 

interested states as they develop and 

implement their plans. 

States would be able to address the 

economic interests of their utilities and 

ratepayers by using the flexibilities in 

this proposed action to: (1) Reduce costs 

to consumers, minimize stranded assets, 

and spur private investments in 

renewable energy and energy efficiency 

technologies and businesses; and (2) if 

they choose, work with other states on 

multi-state approaches that reflect the 

regional structure of electricity 

operating systems that exists in most 

parts of the country and is critical to 

ensuring a reliable supply of affordable 

energy. The proposed rule gives states 

the flexibility to provide a broad range 

of compliance options that recognize 

that the power sector is made up of a 

diverse range of companies that own 

and operate fossil fuel-fired EGUs, 

including vertically integrated 

companies in regulated markets, 

independent power producers, rural 

cooperatives and municipally-owned 

utilities, all of which are likely to have 

different ranges of opportunities to 

reduce GHG emissions while facing 

different challenges in meeting these 

reductions. 

Both existing state programs (such as 

RGGI, the California Global Warming 

Solutions Act program and the Colorado 

Clean Air, Clean Jobs Act program) and 

ideas suggested by stakeholders show 

that there are a number of different ways 

that states can design programs that 

achieve required reductions while 

working within existing market 

mechanisms used to dispatch power 

effectively in the short term and to 

ensure adequate capacity in the long 

term. These programs and programs for 

conventional pollutants, such as the 

Acid Rain Program under Title IV of the 

CAA, have demonstrated that 

compliance with environmental 

programs can be monetized such that it 

is factored into power sector economic 

decision making in ways that reduce the 

cost of controlling pollution, maintain 

electricity system reliability and work 

within the least cost dispatching 

principles that are key to operation of 

our electric power grid. The proposal 

would also allow states to work together 

with individual companies on potential 

specific challenges. These and other 

flexibilities are discussed further in 

Section VIII of the preamble. 

a. CAA Section 111(d) Requirements 

Under CAA section 111(d),6 state 

plans must establish standards of 

performance that reflect the degree of 

emission limitation achievable through 

the application of the ‘‘best system of 

emission reduction’’ that, taking into 

account the cost of achieving such 

reduction and any non-air quality health 

and environmental impacts and energy 

requirements, the Administrator 

determines has been adequately 

demonstrated (BSER).7 Consistent with 

CAA section 111(d), the EPA is 

proposing state-specific goals that 

reflect the EPA’s calculation of the 

emission limitation that each state can 

achieve through the application of the 

BSER. This calculation reflects the 

degree of emission limitation that the 

state plan must achieve in order to 

implement the BSER that the EPA has 

determined has been adequately 

demonstrated and that, in turn, would 

be required to be, and via the 

calculation, has been, applied for the 

affected EGUs in each state. A CAA 

section 111(d) state plan will differ from 

a state implementation plan (SIP) for a 

criteria air pollutant national ambient 

air quality standard (NAAQS) in several 

respects, reflecting the significant 

differences between CAA sections 110 

and 111. A CAA section 110 SIP must 

be designed to meet the NAAQS for a 

criteria air pollutant for a particular 

area—not for a source category—within 

a timeframe specified in the CAA. The 

NAAQS itself is based on the current 

body of scientific evidence and, by law, 

does not reflect consideration of cost. By 

contrast, a CAA section 111(d) state 

plan must be designed to achieve a 

specific level of emission performance 

that has been established for a particular 

source category within a timeframe 

determined by the Administrator and, to 

some extent, by each state. Moreover, 

the emission levels for the source 

category reflect a determination of the 

BSER, which incorporates consideration 

of cost, technical feasibility and other 

factors. 

To determine the BSER for reducing 

CO2 emissions at affected EGUs, the 

EPA considered numerous measures 

that are already being implemented and 

can be implemented more broadly to 


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8The 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) are one example, as they allow either 

of two approaches for controlling landfill gas—by 

recovering the gas as a fuel, for sale, and removing 

from the premises, or by destroying the organic 

content of the gas on the premises using a control 

device. Recovering the gas as a fuel source was a 

practice already being used by some affected 

sources prior to promulgation of the rulemaking. 

improve emission rates and to reduce 

overall CO2 emissions from fossil fuelfired EGUs. Overall, the BSER proposed 

here is based on a range of measures 

that fall into four main categories, or 

‘‘building blocks,’’ which comprise 

improved operations at EGUs, 

dispatching lower-emitting EGUs and 

zero-emitting energy sources, and enduse energy efficiency. All of these 

measures have been amply 

demonstrated via their current 

widespread use by utilities and states. 

The proposed guidelines are 

structured so that states would not be 

required to use each and every one of 

the measures that the EPA determines 

constitute the BSER or to apply any one 

of those measures to the same extent 

that the EPA determines is achievable at 

reasonable cost. Instead, in developing 

its plan, each state will have the 

flexibility to select the measure or 

combination of measures it prefers in 

order to achieve its CO2 emission 

reduction goal. Thus, a state could 

choose to achieve more reductions from 

one measure encompassed by the BSER 

and less from another, or it could 

choose to include measures that were 

not part of the EPA’s BSER 

determination, as long as the state 

achieves the CO2 reductions at affected 

EGUs necessary to meet the goal that the 

EPA has defined as representing the 

BSER. 

As explained in further detail in 

Sections VI, VII and VIII of this 

preamble regarding the agency’s 

determination of the BSER, the EPA is 

offering the opportunity via this 

proposal to comment on the proposed 

BSER, the proposed methodology for 

computing state goals based on 

application of the BSER, and the statespecific data used in the computations. 

Once the final goals have been 

promulgated, a state would no longer 

have an opportunity to request that the 

EPA adjust its CO2 goal. The final statespecific CO2 goals would reflect any 

adjustments as appropriate based on 

comments provided to the EPA to 

address any data errors in the analysis 

for the proposed goals. We expect that 

states will be able to meet the CO2 goals 

because they will represent the 

application of the BSER for the states’ 

affected sources. 

This proposed rule sets forth the state 

goals that reflect the BSER and 

guidelines for states to use in 

developing their plans to reduce CO2

from fossil fuel-fired EGUs. The 

preamble describes the proposed 

expectations for state plans and 

discusses options that the EPA has 

considered. It also explains the EPA’s 

authority to define the BSER, as well as 

state goals, and each state’s 

responsibility to develop and 

implement standards of performance 

that will achieve its CO2 goal. 

Additional detail on various aspects of 

the proposal is included in several 

technical support documents (TSDs) 

and memoranda, which are available in 

the rulemaking docket. 

The proposal was substantially 

informed by the extensive input from 

states and a wide range of stakeholders 

that the EPA sought and has received 

since the summer of 2013. The EPA 

invites further input through public 

comment on all aspects of this proposal. 

2. Summary of the Proposal’s Major 

Provisions 

a. Approach 

In developing this proposed 

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 

subsequent CAA section 111(d) 

rulemakings. These provisions ensure 

that, in concert with the provisions of 

CAA sections 110 and 112, new and 

existing major stationary sources 

operate in ways that address their 

emissions of significant air pollutants 

that are harmful to public health and the 

environment. These requirements call 

on the EPA to develop emission 

guidelines, which reflect the EPA’s 

determination of the BSER, for states to 

follow in formulating compliance plans 

to implement standards of performance 

to achieve emission reductions 

consistent with the BSER. In following 

these provisions, the EPA is proposing 

a BSER based on strategies currently 

being used by states and companies to 

reduce CO2 emissions from EGUs. 

The CAA, as interpreted by the courts, 

identifies several factors for the EPA to 

consider in a BSER determination. 

These include technical feasibility, 

costs, size of emission reductions and 

technology (e.g., whether the system 

promotes the implementation and 

further development of technology). In 

determining the BSER, the EPA 

considered the reductions achievable 

through measures that reduce CO2

emissions from existing fossil fuel-fired 

EGUs either by (1) reducing the CO2

emission rate at those units or (2) 

reducing the units’ CO2 emission total to 

the extent that generation can be shifted 

from higher-emitting fossil fuel-fired 

EGUs to lower- or zero-emitting options. 

As the EPA has done in making BSER 

determinations in previous CAA section 

111(d) rulemakings, the agency 

considered the types of strategies that 

states and owners and operators of 

EGUs are already employing to reduce 

the covered pollutant (in this case, CO2) 

from affected sources (in this case, fossil 

fuel-fired EGUs).8 Across the nation, 

many states, cities and towns, and 

owners and operators of EGUs have 

shown leadership in creating and 

implementing policies and programs 

that reduce CO2 emissions from the 

power sector while achieving other 

economic, environmental and energy 

benefits. Some of these activities, such 

as market-based programs and GHG 

performance standards, directly require 

CO2 emission reductions from EGUs. 

Others reduce CO2 emissions by 

reducing utilization of fossil fuel-fired 

EGUs through, for example, renewable 

portfolio standards (RPS) and energy 

efficiency resource standards (EERS). 

For example, currently 10 states have 

market-based GHG emission programs, 

38 states have renewable portfolio 

standards or goals, and utilities in 47 

states run demand-side energy 

efficiency programs. Many individual 

companies also have significant 

voluntary CO2 emission reduction 

programs. 

Such strategies—and the proposed 

BSER determination—reflect the fact 

that, in almost all states, the production, 

distribution and use of electricity can 

be, and is, undertaken in ways that 

accommodate reductions in both 

pollution emission rates and total 

emissions. Specifically, electricity 

production, at least to some extent, 

takes place interchangeably between 

and among multiple generation facilities 

and different types of generation, a fact 

that Congress, the EPA and the states 

have long relied on in enacting or 

promulgating pollution reduction 

programs, such as Title IV of the CAA, 

the NOX SIP Call, the Cross State Air 

Pollution Rule (CSAPR) and RGGI. 

As a result, the agency, in quantifying 

state goals, assessed what combination 

of electricity production or energy 

demand reduction across generation 

facilities can offer a reasonable-cost, 

technically feasible approach to 

achieving CO2 emission reductions. 

States, in turn, will be able to look 

broadly at opportunities across their 


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9The EPA notes that under the proposed BSER, 

some building blocks would apply to some, but not 

all, affected sources. Specifically, building block 1 

would apply to affected coal-fired steam EGUs, 

building block 2 would apply to all affected steam 

EGUs (both coal-fired and oil/gas-fired), and 

building blocks 3 and 4 would apply to all affected 

EGUs. 

electricity system in devising plans to 

meet their goals. Importantly, states may 

rely on measures that they already have 

in place, including renewable energy 

standards and demand-side energy 

efficiency programs, and the proposal 

details how such existing state programs 

can be incorporated into state plans. 

States will also be able to participate in 

multi-state programs that already exist 

or may create new ones. 

Thus, to determine the BSER for 

reducing CO2 emissions at affected 

EGUs and to establish the numerical 

goals that reflect the BSER, the EPA 

considered numerous measures that can 

and are being implemented to improve 

emission rates and to reduce or limit 

mass CO2 emissions from fossil fuelfired EGUs. These measures encompass 

two basic approaches: (1) Reducing the 

carbon intensity of certain affected 

EGUs by improving the efficiency of 

their operations, and (2) addressing 

affected EGUs’ mass emissions by 

varying their utilization levels. For 

purposes of expressing the BSER as an 

emission limitation, in this case in the 

form of state-level goals, we propose to 

base these two approaches on measures 

grouped into four main categories, or 

‘‘building blocks.’’ These building 

blocks can also be used as a guide to 

states for constructing broad-based, costeffective, long-term strategies to reduce 

CO2 emissions. The EPA believes that 

the application of measures from each of 

the building blocks can achieve CO2

emission reductions at fossil fuel-fired 

EGUs such that, when combined with 

measures from other building blocks, 

the measures represent the ‘‘best system 

of emission reduction . . . adequately 

demonstrated’’ for fossil fuel-fired 

EGUs. The building blocks are: 

1. Reducing the carbon intensity of 

generation at individual affected EGUs 

through heat rate improvements. 

2. Reducing emissions from the most 

carbon-intensive affected EGUs in the 

amount that results from substituting 

generation at those EGUs with 

generation from less carbon-intensive 

affected EGUs (including NGCC units 

under construction). 

3. Reducing emissions from affected 

EGUs in the amount that results from 

substituting generation at those EGUs 

with expanded low- or zero-carbon 

generation. 

4. Reducing emissions from affected 

EGUs in the amount that results from 

the use of demand-side energy 

efficiency that reduces the amount of 

generation required. 

The four building blocks are 

described in detail in Sections VI of this 

preamble. As explained in that section, 

the EPA evaluated each of the building 

blocks individually against the BSER 

criteria and found that each of the 

building blocks independently merits 

consideration as part of the BSER. The 

EPA also evaluated combinations of the 

building blocks against the BSER 

criteria—in particular, a combination of 

all four building blocks and a 

combination of building blocks 1 and 2. 

Based on that evaluation, the EPA 

proposes that the combination of all 

four building blocks is the BSER. The 

combination of all four blocks best 

represents the BSER because it achieves 

greater emission reductions at a lower 

cost, takes better advantage of the wide 

range of measures that states, cities, 

towns and utilities are already using to 

reduce CO2 from EGUs and reflects the 

integrated nature of the electricity 

system and the diversity of electricity 

generation technology. Section VI of this 

preamble also explains how the EPA 

considered more aggressive application 

of measures in each block. This includes 

consideration of more extensive 

application of measures that the EPA 

determined do represent a component of 

the BSER (such as more extensive or 

accelerated application of demand-side 

measures), as well as consideration of 

options in some blocks that the EPA 

determined would not represent the 

BSER for existing sources (such as the 

inclusion of retrofit carbon capture and 

storage or sequestration (CCS) on 

existing EGUs). 

As part of the BSER determination, 

the EPA considered the impacts that 

implementation of the emission 

reductions based on the combination of 

the blocks would have on the cost of 

electricity and electricity system 

reliability. As the preamble details, the 

EPA believes that, both with respect to 

the overall proposed BSER and with 

respect to the individual building 

blocks, the associated costs are 

reasonable. Importantly, the proposed 

BSER, expressed as a numeric goal for 

each state, provides states with the 

flexibility to determine how to achieve 

the reductions (i.e., greater reductions 

from one building block and less from 

another) and to adjust the timing in 

which reductions are achieved, in order 

to address key issues such as cost to 

consumers, electricity system reliability 

and the remaining useful life of existing 

generation assets. 

In sum, the EPA proposes that the 

BSER for purposes of CAA section 

111(d), as applied to existing fossil fuelfired EGUs, is based on a combination 

of measures that reduce CO2 emissions 

and CO2 emission rates and encompass 

all four building blocks.9 We are also 

soliciting comment on application of 

only the first two building blocks as the 

basis for the BSER, while noting that 

application of only the first two 

building blocks achieves fewer CO2

reductions at a higher cost. 

In determining the BSER, we have 

considered the ranges of reductions that 

can be achieved by application of each 

building block, and we have identified 

goals that we believe reflect a reasonable 

degree of application of each building 

block consistent with the BSER criteria. 

Relying on all four building blocks to 

characterize the combination of 

measures that reduce CO2 emissions and 

CO2 emission rates at affected EGUs as 

the basis for the BSER is consistent with 

strategies, actions and measures that 

companies and states are already 

undertaking to reduce GHG emissions 

and with current trends in the electric 

power sector, driven by efforts to reduce 

GHGs as well as by other factors, such 

as advancements in technology. 

Reliance on all four building blocks in 

this way also supports the goals of 

achieving significant and technically 

feasible reductions of CO2 at a 

reasonable cost, while also promoting 

technology and approaches that are 

important for achieving further 

reductions. Finally, the EPA believes 

that the diverse range of measures 

encompassed in the four building blocks 

allows states and sources to take full 

advantage of the inherent flexibility of 

the current regionally interconnected 

and integrated electricity system so as to 

achieve the CO2 goals while continuing 

to meet the demand for electricity 

services in a reliable and affordable 

manner. 

The EPA recognizes that states differ 

in important ways, including in their 

mix of existing EGUs and in their policy 

priorities. Consequently, opportunities 

and preferences for reducing emissions, 

as reflected in each of the building 

blocks, vary across states. While the 

state-specific goals that the EPA is 

proposing in this rule are based on 

consistent application of a single goalsetting methodology across all states, 

the goals account for these key 

differences. The state-specific CO2 goals 

derived from application of the 

methodology vary because, in setting 

the goals for a state, the EPA used data 

specific to each state’s EGUs and certain 


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other attributes of its electricity system 

(e.g., current mix of generation 

resources). 

The proposed BSER and goal-setting 

methodology reflect information 

provided and priorities expressed 

during the EPA’s recent, extensive 

public outreach process. The input we 

received ranged from the states’ desires 

for flexibility and recognition of varying 

state circumstances to the success that 

states and companies have had in 

adopting a range of pollution—and 

demand-reduction strategies. The statespecific approach embodied in both 

CAA section 111(d) and this proposal 

recognizes that ultimately states are the 

most knowledgeable about their specific 

circumstances and are best positioned to 

evaluate and leverage existing and new 

generation capacity and programs to 

reduce CO2 emissions. 

To meet its goal, each state will be 

able to design programs that use the 

measures it selects, and these may 

include the combination of building 

blocks most relevant to its specific 

circumstances and policy preferences. 

States may also identify technologies or 

strategies that are not explicitly 

mentioned in any of the four building 

blocks and may use those technologies 

or strategies as part of their overall plans 

(e.g., market-based trading programs or 

construction of new natural combined 

cycle units or nuclear plants). Further, 

the EPA’s approach allows multi-state 

compliance strategies. 

The agency also recognizes the 

important functional relationship 

between the period of time over which 

measures are deployed and the 

stringency of emission limitations those 

measures can achieve in a practical and 

reasonable cost way. Because, for this 

proposal, the EPA is proposing a 10-year 

period over which to achieve the full 

required CO2 reductions, a period that 

begins more than five years from the 

date of this proposal, a state could take 

advantage of this relationship in the 

design of its program by using relevant 

combinations of building blocks to 

achieve its state goal in a manner that 

provides for electricity system 

reliability, avoids the creation of 

stranded assets and has a reasonable 

cost. 

b. State Goals and Flexibilities 

In this action, the EPA is proposing 

state-specific rate-based goals that state 

plans must be designed to meet. These 

state-specific goals are based on an 

assessment of the amount of emissions 

that can be reduced at existing fossil 

fuel-fired EGUs through application of 

the BSER, as required under CAA 

section 111(d). The agency is proposing 

state-specific final goals that must be 

achieved by no later than the year 2030. 

The proposed final goals reflect the 

EPA’s quantification of adjusted stateaverage emission rates from affected 

EGUs that could be achieved at 

reasonable cost by 2030 through 

implementation of the four building 

blocks described above. 

The EPA recognizes that, with many 

measures, states can achieve emission 

reductions in the short-term, though the 

full effects of implementation of other 

measures, such as demand-side energy 

efficiency (EE) programs and the 

addition of renewable energy (RE) 

generating capacity, can take longer. 

Thus, the EPA is proposing interim 

goals that states must meet beginning in 

2020. The proposed interim goals would 

apply over a 2020–2029 phase-in 

period. They reflect the level of 

reductions in CO2 emissions and 

emission rates and the extent of the 

application of the building blocks that 

would be presumptively approvable in 

a state plan during the ramp-up to 

achieving the final goal. 

The EPA is proposing to allow each 

state flexibility with regard to the form 

of the goal. A state could adopt the ratebased form of the goal established by the 

EPA or an equivalent mass-based form 

of the goal. A multi-state approach 

incorporating either a rate- or massbased goal would also be approvable 

based upon a demonstration that the 

state’s plan would achieve the 

equivalent in stringency, including 

compliance timing, to the state-specific 

rate-based goal set by the EPA. 

We believe that this approach to 

establishing requirements for states in 

developing their plans responds both to 

the needs of an effectively implemented 

program and to the range of viewpoints 

expressed by stakeholders regarding the 

simultaneous need for both flexibility 

and clear guidance on what would 

constitute an approvable state plan. We 

likewise believe that this approach 

represents a reasonable balance between 

two competing objectives grounded in 

CAA section 111(d)—a need for rigor 

and consistency in calculating emission 

reductions reflecting the BSER and a 

need to provide the states with 

flexibility in establishing and 

implementing the standards of 

performance that reflect those emission 

reductions. The importance of this 

balance is heightened by the fact that 

the operations of the electricity system 

itself rely on the flexibility made 

available and achieved through 

dispatching between and among 

multiple interconnected EGUs, demand 

management and end-use energy 

efficiency. We view the proposed goals 

as providing rigor where required by the 

statute with respect to the amount of 

emission reductions, while providing 

states with flexibility where permitted 

by the statute, particularly with respect 

to the range of measures that a state 

could include in its plan. This approach 

recognizes that state plans for emission 

reductions can, and must, be consistent 

with a vibrant and growing economy 

and supply of reliable, affordable 

electricity to support that economy. It 

further reflects the growing trend, as 

exemplified by many state and local 

clean energy policies and programs, to 

shift energy production away from 

carbon-intensive fuels to a modern, 

more sustainable system that puts 

greater reliance on renewable energy, 

energy efficiency and other low-carbon 

energy options. 

c. State Plans 

i. Plan Approach 

Each state will determine, and 

include in its plan, emission 

performance levels for its affected EGUs 

that are equivalent to the state-specific 

CO2 goal in the emission guidelines, as 

well as the measures needed to achieve 

those levels and the overall goal. As part 

of determining these levels, the state 

will decide whether it will adopt the 

rate-based form of the goal established 

by the EPA or translate the rate-based 

goal to a mass-based goal. The state 

must then establish a standard, or set of 

standards, of performance, as well as 

implementing and enforcing measures, 

to achieve the emission performance 

level specified in the state plan. The 

state may choose the measures it will 

include in its plan to achieve its goal. 

The state may use the same set of 

measures as in the EPA’s approach to 

setting the goals, or the state may use 

other or additional measures to achieve 

the required CO2 reductions. 

A state plan must include enforceable 

CO2 emission limits that apply to 

affected EGUs. In doing so, a state plan 

may take a portfolio approach, which 

could include enforceable CO2 emission 

limits that apply to affected EGUs as 

well as other enforceable measures, 

such as RE and demand-side EE 

measures, that avoid EGU CO2

emissions and are implemented by the 

state or by another entity. The plan must 

also include a process for reporting on 

plan implementation, progress toward 

achieving CO2 goals, and 

implementation of corrective actions, if 

necessary. No less frequently than every 

two rolling calendar years, beginning 

January 1, 2022, the state will be 

required to compare emission 

performance achieved by affected EGUs 


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10Presidential Memorandum—Power Sector 

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

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

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

in the state with the emissions 

performance projected in the state plan, 

and report that to the EPA. 

In this action, the EPA is also 

proposing guidelines for states to follow 

in developing their plans. These 

guidelines include approvability 

criteria, requirements for state plan 

components, the process and timing for 

state plan submittal and the process and 

timing for demonstrating achievement 

of the CO2 emission performance level 

in the state plan. The proposed 

guidelines provide states with options 

for meeting the state-specific goals 

established by the EPA in a flexible 

manner that accommodates a diverse 

range of state approaches. 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. 

With respect to the structure of the 

state plans, the EPA, in its extensive 

outreach efforts, heard from a wide 

range of stakeholders that the EPA 

should authorize state plans to include 

a portfolio of actions that encompass a 

diverse set of programs and measures 

that achieve either a rate-based or massbased emission performance level for 

affected EGUs but that do not place legal 

responsibility for achieving the entire 

amount of the emission performance 

level on the affected EGUs. In view of 

this strong sentiment from stakeholders, 

the EPA is proposing that state plans 

that take this portfolio approach would 

be approvable, provided that they meet 

other key requirements such as 

achieving the required emission 

reductions over the appropriate 

timeframes. Plans that do directly assure 

that affected EGUs achieve all of the 

required emission reductions (such as 

the mass-based programs being 

implemented in California and the RGGI 

states) would also be approvable 

provided that they meet other key 

requirements, such as achieving the 

required emission reductions over the 

appropriate timeframes. 

ii. State Plan Components 

The EPA is proposing to evaluate and 

approve state plans based on four 

general criteria: (1) Enforceable 

measures that reduce EGU CO2

emissions; (2) projected achievement of 

emission performance equivalent to the 

goals established by the EPA, on a 

timeline equivalent to that in the 

emission guidelines; (3) quantifiable 

and verifiable emission reductions; and 

(4) a process for reporting on plan 

implementation, progress toward 

achieving CO2 goals, and 

implementation of corrective actions, if 

necessary. In addition, each state plan 

must follow the EPA framework 

regulations at 40 CFR 60.23. The 

proposed components of states plans 

are: 

• Identification of affected entities 

• Description of plan approach and 

geographic scope 

• Identification of state emission 

performance level 

• Demonstration that plan is projected 

to achieve emission performance level 

• Identification of emission standards 

• Demonstration that each emission 

standard is quantifiable, nonduplicative, permanent, verifiable, 

and enforceable 

• Identification of monitoring, 

reporting, and recordkeeping 

requirements 

• Description of state reporting 

• Identification of milestones 

• Identification of backstop measures 

• Certification of hearing on state plan 

• Supporting material 

iii. Process for State Plan Submittal and 

Review 

Recognizing the urgent need for 

actions to reduce GHG emissions, and in 

accordance with the Presidential 

Memorandum,10 the EPA expects to 

finalize this rulemaking by June 1, 2015. 

The Presidential Memorandum also 

calls for a deadline of June 30, 2016, for 

states to submit their state plans. The 

EPA is proposing that each state must 

submit a plan to the EPA by June 30, 

2016. However, the EPA recognizes that 

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, 

coordination with third parties, and 

coordination among states involved in 

multi-state plans. Therefore, the EPA is 

proposing an optional two-phased 

submittal process for state plans. Each 

state would be required to submit a plan 

by June 30, 2016, that contains certain 

required components. If a state needs 

additional time to submit a complete 

plan, then the state must submit an 

initial plan by June 30, 2016 that 

documents the reasons the state needs 

more time and includes commitments to 

concrete steps that will ensure that the 

state will submit a complete plan by 

June 30, 2017 or 2018, as appropriate. 

To be approvable, the initial plan must 

include specific components, including 

a description of the plan approach, 

initial quantification of the level of 

emission performance that will be 

achieved in the plan, a commitment to 

maintain existing measures that limit 

CO2 emissions, an explanation of the 

path to completion, and a summary of 

the state’s response to any significant 

public comment on the approvability of 

the initial plan, as described in Section 

VIII.E of this preamble. 

If the initial plan includes those 

components and if the EPA does not 

notify the state that the initial plan does 

not contain the required components, 

the extension of time to submit a 

complete plan will be deemed granted 

and a state would have until June 30, 

2017, to submit a complete plan if the 

geographic scope of the plan is limited 

to that state. If the state develops a plan 

that includes a multi-state approach, it 

would have until June 30, 2018 to 

submit a complete plan. Further, the 

EPA is proposing that states 

participating in a multi-state plan may 

submit a single joint plan on behalf of 

all of the participating states. 

Following submission of final plans, 

the EPA will review plan submittals for 

approvability. Given the diverse 

approaches states may take to meet the 

emission performance goals in the 

emission guidelines, the EPA is 

proposing to extend the period for EPA 

review and approval or disapproval of 

plans from the four-month period 

provided in the EPA framework 

regulations to a twelve-month period. 

iv. Timing of Compliance 

As states, industry groups and other 

stakeholders have made clear, the EPA 

recognizes that the measures states have 

been and will be taking to reduce CO2

emissions from existing EGUs can take 

time to implement. Thus, we are 

proposing that, while states must begin 

to make reductions by 2020, full 

compliance with the CO2 emission 

performance level in the state plan must 

be achieved by no later than 2030. 

Under this proposed option, a state 

would need to meet an interim CO2

emission performance level on average 

over the 10-year period from 2020–2029, 

as well as achieve its final CO2 emission 

performance level by 2030 and maintain 

that level subsequently. This proposed 

option is based on the application of a 

range of measures from all four building 

blocks, and the agency believes that this 

approach for compliance timing is 

reasonable and appropriate and would 

best support the optimization of overall 


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11www2.epa.gov/cleanpowerplantoolbox. 

12The EPA has used social cost of carbon (SCC) 

estimates—i.e., the monetary value of impacts 

associated with a marginal change in CO2 emissions 

in a given year—to analyze CO2 climate impacts of 

this rulemaking. The four SCC estimates are 

associated with different discount rates (model 

average at 2.5 percent discount rate, 3 percent, and 

5 percent; 95th percentile at 3 percent), and each 

increases over time. In this summary, the EPA 

provides the estimate of climate benefits associated 

with the SCC value deemed to be central: The 

model average at 3 percent discount rate. 

CO2 reductions. The agency is also 

requesting comment on an alternative 

option, a 5-year period for compliance, 

in combination with a less stringent set 

of CO2 emission performance levels. 

These options are fully described in 

Section VIII of this preamble, and the 

state goals associated with the 

alternative option are described in 

Section VII.E of this preamble. The EPA 

is also seeking comment on different 

combinations of building blocks and 

different levels of stringency for each 

building block. 

The EPA is also proposing that 

measures that a state takes after the date 

of this proposal, or programs already in 

place, which result in CO2 emission 

reductions during the 2020–2030 

period, would apply toward 

achievement of the state’s 2030 CO2

emission goal. Thus, states with 

currently existing programs and 

policies, and states that put in place 

new programs and policies early, will be 

better positioned to achieve the goals. 

v. Resources for States 

To respond to requests from states for 

methodologies, tools and information to 

assist them in designing and 

implementing their plans, the EPA, in 

consultation with the U.S. Department 

of Energy and other federal agencies, as 

well as states, is collecting and 

developing available resources and is 

making those resources available to the 

states via a dedicated Web site.11 As we 

and others continue to develop tools, 

templates and other resources, we will 

update the Web site. We intend, during 

the public comment period, to work 

actively with the states on resources that 

will be helpful to them in both 

developing and implementing their 

plans. 

3. Projected National-Level Emission 

Reductions 

Under the proposed guidelines, the 

EPA projects annual CO2 reductions of 

26 to 30 percent below 2005 levels 

depending upon the compliance year. 

These guidelines will also result in 

important reductions in emissions of 

criteria air pollutants, including sulfur 

dioxide (SO2), nitrogen oxides (NOX) 

and directly emitted fine particulate 

matter (PM2.5). A thorough discussion of 

the EPA’s analysis is presented in 

Section X.A of this preamble and in 

Chapter 3 of the Regulatory Impact 

Analysis (RIA) included in the docket 

for this rulemaking. 

4. Costs and Benefits 

Actions taken to comply with the 

proposed guidelines will reduce 

emissions of CO2 and other air 

pollutants, including SO2, NOX and 

directly emitted PM2.5, from the electric 

power industry. 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 

EPA has calculated illustrative costs and 

benefits in two ways: One based on an 

assumption of individual state plans 

and another based on an assumption 

that states will opt for multi-state plans. 

The illustrative costs and benefits are 

based upon compliance approaches that 

reflect a range of measures consisting of 

improved operations at EGUs, 

dispatching lower-emitting EGUs and 

zero-emitting energy sources, and 

increasing levels of end-use energy 

efficiency. 

Assuming that states comply with the 

guidelines collaboratively (referred to as 

the regional compliance approach), the 

EPA estimates that, in 2020, this 

proposal will yield monetized climate 

benefits of approximately $17 billion 

(2011$) using a 3 percent discount rate 

(model average) relative to the 2020 base 

case, as shown in Table 1.12 The air 

pollution health co-benefits associated 

with reducing exposure to ambient 

PM2.5 and ozone through emission 

reductions of precursor pollutants in 

2020 are estimated to be $16 billion to 

$37 billion using a 3 percent discount 

rate and $15 billion to $34 billion 

(2011$) using a 7 percent discount rate 

relative to the 2020 base case. The 

annual compliance costs are estimated 

using the Integrated Planning Model 

(IPM) and include demand-side energy 

efficiency program and participant costs 

as well as monitoring, reporting and 

recordkeeping costs. In 2020, total 

compliance costs of this proposal are 

approximately $5.5 billion (2011$). The 

quantified net benefits (the difference 

between monetized benefits and 

compliance costs) in 2020 are estimated 

to be $28 billion to $49 billion (2011$) 

using a 3 percent discount rate (model 

average). As reflected in Table 2, climate 

benefits are approximately $30 billion 

in 2030 using a 3 percent discount rate 

(model average, 2011$) relative to the 

2030 base case assuming a regional 

compliance approach for the proposal. 

Health co-benefits are estimated to be 

approximately $25 to $59 billion (3 

percent discount rate) and $23 to $54 

billion (7 percent discount rate) relative 

to the 2030 base case (2011$). In 2030, 

total compliance costs for the proposed 

option regional approach are 

approximately $7.3 billion (2011$). The 

net benefits for this proposal increase to 

approximately $48 billion to $82 billion 

(3 percent discount rate model average, 

2011$) in 2030 for the proposed option 

regional compliance approach. 

In comparison, if states choose to 

comply with the guidelines on a statespecific basis (referred to as state 

compliance approach), the climate 

benefits in 2020 are expected to be 

approximately $18 billion (3 percent 

discount rate, model average, 2011$), as 

Table 1 shows. Health co-benefits are 

estimated to be $17 to $40 billion (3 

percent discount rate) and $15 to $36 

billion (7 percent discount rate). Total 

compliance costs are approximately 

$7.5 billion annually in 2020. Net 

benefits in 2020 are estimated to be $27 

to $50 billion (3 percent model average 

discount rate, 2011$). In 2030, as shown 

on Table 2, climate benefits are 

approximately $31 billion using a 3 

percent discount rate (model average, 

2011$) relative to the 2030 base case 

assuming a state compliance approach. 

Health co-benefits are estimated to be 

approximately $27 to $62 billion (3 

percent discount rate) and $24 to $56 

billion (7 percent discount rate) relative 

to the 2030 base case (2011$). In 2030, 

total compliance costs for the state 

approach are approximately $8.8 billion 

(2011$). In 2030, these net benefits are 

estimated to be approximately $49 to 

$84 billion (3 percent discount rate, 

2011$) assuming a state compliance 

approach. 


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

GUIDELINES IN 2020 a

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Proposed Guidelines Regional Compliance Approach 

Climate benefits b .................................................................................... $17. 

Air pollution health co-benefits c .............................................................. $16 to $37 ..................................... $15 to $34. 

Total Compliance Costs d ........................................................................ $5.5 ................................................ $5.5. 

Net Monetized Benefits e ......................................................................... $28 to $49 ..................................... $26 to $45. 

Non-monetized Benefits .......................................................................... Direct exposure to SO2 and NO2. 

1.3 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

Proposed Guidelines State Compliance Approach 

Climate benefits b .................................................................................... $18 

Air pollution health co-benefits c .............................................................. $17 to $40 ..................................... $15 to $36. 

Total Compliance Costs d ........................................................................ $7.5 ................................................ $7.5. 

Net Monetized Benefits e ........................................................................ $27 to $50 ..................................... $26 to $46. 

Non-monetized Benefits .......................................................................... Direct exposure to SO2 and NO2. 

1.5 tons. 

Ecosystem effects. 

Visibility impairment. 

aAll estimates are for 2020, and are rounded to two significant figures, so figures may not sum. 

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

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

and subsequent damages occur over many years. The benefit estimates in this table are based on the average SCC estimated for a 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. As shown in the RIA, climate benefits 

are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 

3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted 

PM2.5, SO2 and NOX. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine 

particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed guidelines 

and a discount rate of approximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model 

average). The RIA includes combined climate and health estimates based on these additional discount rates. 

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

GUIDELINES IN 2030 a

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Proposed Guidelines Regional Compliance Approach 

Climate benefits b ..................................................................................................... $30. 

Air pollution health co-benefits c .............................................................................. $25 to $59 .............................................. $23 to $54. 

Total Compliance Costs d ........................................................................................ $7.3 ........................................................ $7.3. 

Net Monetized Benefits e ......................................................................................... $48 to $82 .............................................. $46 to $77. 

Non-monetized Benefits .......................................................................................... Direct exposure to SO2 and NO2. 

1.7 tons of Hg and 580 tons of HCl. 

Ecosystem Effects. 

Visibility impairment. 

Proposed Guidelines State Compliance Approach 

Climate benefits b ..................................................................................................... $31. 

Air pollution health co-benefits c .............................................................................. $27 to $62 .............................................. $24 to $56. 

Total Compliance Costs d ........................................................................................ $8.8 ........................................................ $8.8. 

Net Monetized Benefits e ......................................................................................... $49 to $84 .............................................. $46 to $79. 


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13Although CO2 is the predominant greenhouse 

gas released by the power sector, electricity 

generating units also emit small amounts of nitrous 

oxide and methane. See RIA Chapter 2 for more 

detail about power sector emissions and the U.S. 

Greenhouse Gas Reporting Program’s power sector 

summary, http://www.epa.gov/ghgreporting/

ghgdata/reported/powerplants.html. 

14A 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 2020 may represent 20 

full-time jobs or 40 half-time jobs. 15 79 FR 1430. 

16 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66,496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

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

GUIDELINES IN 2030 a—Continued 

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Non-monetized Benefits .......................................................................................... Direct exposure to SO2 and NO2. 

2.1 tons of Hg and 590 tons of HCl. 

Ecosystem effects. 

Visibility impairment. 

aAll estimates are for 2030, and are rounded to two significant figures, so figures may not sum. 

bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC than to the other estimates because CO2 emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the average SCC estimated for a 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 

percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent 

in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed guidelines and a discount rate of 

approximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates. 

There are additional important 

benefits that the EPA could not 

monetize. These unquantified benefits 

include climate benefits from reducing 

emissions of non-CO2 greenhouse gases 

(e.g., nitrous oxide and methane) 13 and 

co-benefits from reducing direct 

exposure to SO2, NOX and hazardous air 

pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing 

ecosystem effects and visibility 

impairment. 

In addition to the cost and benefits of 

the rule, the EPA projects the 

employment impacts of the guidelines. 

We project job gains and losses relative 

to base case for the electric generation, 

coal and natural gas production, and 

demand side energy efficiency sectors. 

In 2020, we project job growth of 25,900 

to 28,000 job-years 14 in the power 

production and fuel extraction sectors, 

and we project an increase of 78,800 

jobs in the demand-side energy 

efficiency sector. 

Based upon the foregoing, it is clear 

that the monetized benefits of this 

proposal are substantial and far 

outweigh the costs. 

B. Organization and Approach for This 

Proposed Rule 

This action presents the EPA’s 

proposed emission guidelines for states 

to consider in developing plans to 

reduce GHG emissions from the electric 

power sector. Section II provides 

background on climate change impacts 

from GHG emissions, GHG emissions 

from fossil fuel-fired EGUs and the 

utility power sector and CAA section 

111(d) requirements. Section III presents 

a summary of the EPA’s stakeholder 

outreach efforts, key messages provided 

by stakeholders, state policies and 

programs that reduce GHG emissions, 

and conclusions. In Section IV of the 

preamble, we present a summary of the 

rule requirements and the legal basis for 

these. Section V explains the EPA 

authority to regulate CO2 and EGUs, 

identifies affected sources, and 

describes the proposed treatment of 

source categories. Section VI describes 

the use of building blocks for setting 

state goals and key considerations in 

doing so. Sections VII and VIII provide 

explanations of the proposed statespecific goals and the proposed 

requirements for state plans, 

respectively. Implications for the new 

source review and Title V programs and 

potential interactions with other EPA 

rules are described in Section IX. 

Impacts of the proposed action are then 

described in Section X, followed by a 

discussion of statutory and executive 

order reviews in Section XI and the 

statutory authority for this action in 

Section XII. 

We note that this rulemaking overlaps 

in certain respects with two other 

related rulemakings: The January 2014 

proposed rulemaking that the EPA 

published on January 8, 2014 for CO2

emissions from newly constructed 

affected sources,15 and the rulemaking 

for modified and reconstructed sources 

that the EPA is proposing at the same 

time as this rulemaking. Each of these 

three rulemakings is independent of the 

other two, and each has its own 

rulemaking docket. Accordingly, 

commenters who wish to comment on 

any aspect of this rulemaking, including 

a topic that overlaps an aspect of one or 

both of the other two related 

rulemakings, should make those 

comments on this rulemaking. 

II. Background 

In this section, we discuss climate 

change impacts from GHG emissions, 

both on public health and public 

welfare, present information about GHG 

emissions from fossil fuel fired EGUs, 

and summarize the statutory and 

regulatory requirements relevant to this 

rulemaking. 

A. Climate Change Impacts From GHG 

Emissions 

In 2009, the EPA Administrator 

issued the document known as the 

Endangerment Finding under CAA 

section 202(a)(1).16 In the Endangerment 

Finding, which focused on public 

health and public welfare impacts 

within the United States, the 

Administrator found that elevated 

concentrations of GHGs in the 

atmosphere may reasonably be 

anticipated to endanger public health 

and welfare of current and future 

generations. We summarize these 

adverse effects on public health and 

welfare briefly here. 

1. Public Health Impacts Detailed in the 

2009 Endangerment Finding 

Climate change caused by human 

emissions of GHGs threatens public 

health in multiple ways. By raising 

average temperatures, climate change 


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17National Research Council, Understanding 

Earth’s Deep Past, p. 1. 

18 Id., p.138. 

19National Research Council, Climate 

Stabilization Targets, p. 3. 

20U.S. Global Change Research Program, Climate 

Change Impacts in the United States: The Third 

National Climate Assessment, May 2014 Available 

at http://nca2014.globalchange.gov/. 

increases the likelihood of heat waves, 

which are associated with increased 

deaths and illnesses. While climate 

change also increases the likelihood of 

reductions in cold-related mortality, 

evidence indicates that the increases in 

heat mortality will be larger than the 

decreases in cold mortality in the 

United States. Compared to a future 

without climate change, climate change 

is expected to increase ozone pollution 

over broad areas of the U.S., including 

in the largest metropolitan areas with 

the worst ozone problems, and thereby 

increase the risk of morbidity and 

mortality. Other public health threats 

also stem from projected increases in 

intensity or frequency of extreme 

weather associated with climate change, 

such as increased hurricane intensity, 

increased frequency of intense storms, 

and heavy precipitation. Increased 

coastal storms and storm surges due to 

rising sea levels are expected to cause 

increased drownings and other health 

impacts. 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 caused by human 

emissions of GHGs also threatens public 

welfare in multiple ways. Climate 

changes are expected to place large 

areas of the country at serious risk of 

reduced water supplies, increased water 

pollution, and increased occurrence of 

extreme events such as floods and 

droughts. Coastal areas are expected to 

face increased risks from storm and 

flooding damage to property, as well as 

adverse impacts from rising sea level, 

such as land loss due to inundation, 

erosion, wetland submergence and 

habitat loss. Climate change is expected 

to result in an increase in peak 

electricity demand, and extreme 

weather from climate change threatens 

energy, transportation, and water 

resource infrastructure. Climate change 

may exacerbate ongoing environmental 

pressures in certain settlements, 

particularly in Alaskan indigenous 

communities. Climate change also 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 

As outlined in Section VIII.A. of the 

2009 Endangerment Finding, the EPA’s 

approach to providing the technical and 

scientific information to inform the 

Administrator’s judgment regarding the 

question of whether GHGs endanger 

public health and welfare was to rely 

primarily upon the recent, major 

assessments by the U.S. Global Change 

Research Program (USGCRP), the 

Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC) of the National 

Academies. 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. Since the 

administrative record concerning the 

Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, 

a number of such assessments have been 

released. These assessments include the 

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 ‘‘Climate 

Change Impacts in the United States’’ 

(Climate Change Impacts), 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 reviewed these new 

assessments and finds that the improved 

understanding of the climate system 

they present strengthens the case that 

GHGs endanger public health and 

welfare. 

In addition, these assessments 

highlight the urgency of the situation as 

the concentration of CO2 in the 

atmosphere continues to rise. Absent a 

reduction in emissions, a recent 

National Research Council of the 

National Academies assessment 

projected that concentrations by the end 

of the century would increase to levels 

that the Earth has not experienced for 

millions of years.17 In fact, that 

assessment stated that ‘‘the magnitude 

and rate of the present greenhouse gas 

increase place the climate system in 

what could be one of the most severe 

increases in radiative forcing of the 

global climate system in Earth 

history.’’ 18

What this means, as stated in another 

NRC assessment, is that: 

Emissions of carbon dioxide 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 carbon dioxide 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 reductions choices made 

today matter in determining impacts 

experienced not just over the next few 

decades, but in the coming centuries and 

millennia.19

Moreover, due to the time-lags 

inherent in the Earth’s climate, the 

Climate Stabilization Targets assessment 

notes that the full warming from any 

given concentration of CO2 reached will 

not be realized for several centuries. 

The recently released USGCRP 

‘‘Climate Change Impacts’’ assessment 20

emphasizes that climate change is 

already happening now and it is 

happening in the United States. The 

assessment documents the increases in 

some extreme weather and climate 

events in recent decades, the damage 

and disruption to infrastructure and 

agriculture, and projects continued 

increases in impacts across a wide range 

of peoples, sectors, and ecosystems. 

These assessments underscore the 

urgency of reducing emissions now: 

Today’s emissions will otherwise lead 

to raised atmospheric concentrations for 

thousands of years, and raised Earth 

system temperatures for even longer. 

Emission reductions today will benefit 

the public health and public welfare of 

current and future generations. 

Finally, it should be noted that the 

concentration of carbon dioxide in the 

atmosphere continues to rise 

dramatically. In 2009, the year of the 

Endangerment Finding, the average 

concentration of carbon dioxide as 


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

co2_annmean_mlo.txt. 

22http://www.esrl.noaa.gov/gmd/ccgg/trends/. 

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

and Sinks: 1990–2012’’, Report EPA 430–R–14–003, 

United States Environmental Protection Agency, 

April 15, 2014. 

24Sinks are a physical unit or process that stores 

GHGs, such as forests or underground or deep sea 

reservoirs of carbon dioxide. 

25From Table ES–4 of ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2012, 

Report EPA 430–R–14–003, United States 

Environmental Protection Agency, April 15, 2014. 26From Table ES–2 ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2012’’, 

Report EPA 430–R–14–003, United States 

Environmental Protection Agency, April 15, 2014. 27From Table 3–1 ‘‘Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2012’’, Report EPA 

430–R–14–003, United States Environmental 

Protection Agency, April 15, 2014. 28From Table 3–5 ‘‘Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2012’’, Report EPA 

430–R–14–003, United States Environmental 

Protection Agency, April 15, 2014. 

29U.S. Energy Information Administration (EIA), 

‘‘Table 7.2b Electricity Net Generation: Electric 

Power Sector Electric Power Sector,’’ data from 

April 2014 Monthly Energy Review, release date 

April 25, 2014. Available at: http://www.eia.gov/

totalenergy/data/browser/

xls.cfm?tbl=T07.02B&freq=m. 

30Based on Table 6.3 (New Utility Scale 

Generating Units by Operating Company, Plant, 

Month, and Year) of the U.S. Energy Information 

Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable 

Continued 

measured on top of Mauna Loa was 387 

parts per million.21 The average 

concentration in 2013 was 396 parts per 

million. And the monthly concentration 

in April of 2014 was 401 parts per 

million, the first time a monthly average 

has exceeded 400 parts per million 

since record keeping began at Mauna 

Loa in 1958, and for at least the past 

800,000 years according to ice core 

records.22

B. GHG Emissions From Fossil FuelFired EGUs 

Fossil fuel-fired electric utility 

generating units (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 units, coal-fired units are by 

far the largest emitters. This section 

describes the amounts of those 

emissions and places those amounts in 

the context of the national inventory of 

GHGs. 

The EPA prepares the official U.S. 

Inventory of Greenhouse Gas Emissions 

and Sinks 23 (the U.S. GHG Inventory) to 

comply with commitments under the 

United Nations Framework Convention 

on Climate Change (UNFCCC). This 

inventory, which includes recent trends, 

is organized by industrial sectors. It 

provides the information in Table 3 

below, which presents total U.S. 

anthropogenic emissions and sinks 24 of 

GHGs, including CO2 emissions, for the 

years 1990, 2005 and 2012. 

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

[Teragram carbon dioxide equivalent (Tg CO2 Eq.)] 25

Sector 1990 2005 2012 

Energy .......................................................................................................................................... 5,260.1 6,243.5 5,498.9 

Industrial Processes .................................................................................................................... 316.1 334.9 334.4 

Solvent and Other Product Use .................................................................................................. 4.4 4.4 4.4 

Agriculture .................................................................................................................................... 473.9 512.2 526.3 

Land Use, Land-Use Change and Forestry ................................................................................ 13.7 25.5 37.8 

Waste ........................................................................................................................................... 165.0 133.2 124.0 

Total Emissions ........................................................................................................................... 6,233.2 7,253.8 6,525.6 

Land Use, Land-Use Change and Forestry (Sinks) .................................................................... (831.3) (1,030.7) (979.3) 

Net Emissions (Sources and Sinks) ............................................................................................ 5,402.1 6,223.1 5,546.3 

Total fossil energy-related CO2

emissions (including both stationary 

and mobile sources) are the largest 

contributor to total U.S. GHG emissions, 

representing 77.7 percent of total 2012 

GHG emissions.26 In 2012, fossil fuel 

combustion by the electric power 

sector—entities that burn fossil fuel and 

whose primary business is the 

generation of electricity—accounted for 

38.7 percent of all energy-related CO2

emissions.27 Table 4 below presents 

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

2012. 

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

[Tg CO2] 28

GHG emissions 1990 2005 2012 

Total CO2 from fossil fuel combustion EGUs .............................................................................. 1,820.8 2,402.1 2,022.7 

—from coal ........................................................................................................................... 1,547.6 1,983.8 1,511.2 

—from natural gas ................................................................................................................ 175.3 318.8 492.2 

—from petroleum .................................................................................................................. 97.5 99.2 18.8 

C. The Utility Power Sector 

Electricity in the United States is 

generated by a range of sources—from 

power plants that use fossil fuels like 

coal, oil, and natural gas, to non-fossil 

sources, such as nuclear, solar, wind 

and hydroelectric power. In 2013, over 

67 percent of power in the U.S. was 

generated from the combustion of coal, 

natural gas, and other fossil fuels, over 

40 percent from coal and over 26 

percent from natural gas.29 In recent 

years, though, the proportion of new 

renewable generation coming on line 

has increased dramatically. For 

instance, over 38 percent of new 

generating capacity (over 5 GW out of 

13.5 GW) built in 2013 used renewable 

power generation technologies.30


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energy sources: solar, wind, hydro, geothermal, 

landfill gas, and biomass. Available at: http://

www.eia.gov/electricity/monthly/epm_table_

grapher.cfm?t=epmt_6_03. 

31CAA § 111(b)(1)(A). 

32See 40 CFR 60 subparts Cb–OOOO. 

33CAA § 111(b)(1)(B), 111(a)(1). 

34CAA section 111(d)(2)(A). 

35CAA section 111(d)(2)(A). 

36The EPA is aware of at least four affected 

sources located in Indian Country: Two on Navajo 

lands—the Navajo Generating Station and the Four 

Corners Generating Station; one on Ute lands—the 

Bonanza Generating Station; and one on Fort 

Mojave lands, the South Point Energy Center. The 

affected EGUs at the first three plants are coal-fired 

EGUs. The fourth affected EGU is an NGCC facility. 

37 ‘‘State Plans for the Control of Certain 

Pollutants From Existing Facilities,’’ 40 FR 53,340 

(Nov. 17, 1975). 

38The most recent amendment was in 77 FR 9304 

(Feb. 16, 2012). 

39 40 CFR 60.22. In the 1975 rulemaking, the EPA 

explained that it used the term ‘‘emissions 

guidelines’’—instead of emissions limitations—to 

make clear that guidelines would not be binding 

requirements applicable to the sources, but instead 

are ‘‘criteria for judging the adequacy of State 

plans.’’ 40 FR at 53,343. 

40 40 CFR 60.23(a)(1). 

41 40 CFR 60.27(b). 

42See 40 CFR 60.27(a). 

43See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 Fed. Reg. 

12,022 (Mar. 1, 1977); ‘‘Standards of Performance 

for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,’’ 42 FR 55,796 (Oct. 18, 1977); 

‘‘Kraft Pulp Mills, Notice of Availability of Final 

Guideline Document,’’ 44 FR 29,828 (May 22, 

1979); ‘‘Primary Aluminum Plants; Availability of 

Final Guideline Document,’’ 45 FR 26,294 (Apr. 17, 

1980); ‘‘Standards of Performance for New 

Stationary Sources and Guidelines for Control of 

Existing Sources: Municipal Solid Waste Landfills, 

Final Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

This range of different power plants 

generates electricity that is transmitted 

and distributed through a complex 

system of interconnected components to 

industrial, business, and residential 

consumers. 

The utility power sector is unique in 

that, unlike other sectors where the 

sources operate independently and on a 

local scale, power sources operate in a 

complex, interconnected grid system 

that typically is regional in scale. In 

addition, the U.S. economy depends on 

this sector for a reliable supply of power 

at a reasonable cost. 

In the U.S., much of the existing 

power generation fleet in the 

infrastructure is aging. There has been, 

and continues to be, technological 

advancement in many areas, including 

energy efficiency, solar power 

generation, and wind power generation. 

Advancements and innovation in power 

sector technologies provide the 

opportunity to address CO2 emission 

levels at affected power plants while at 

the same time improving the overall 

power system in the U.S. by lowering 

the carbon intensity of power 

generation, and ensuring a continued 

reliable supply of power at a reasonable 

cost. 

D. Statutory and Regulatory 

Requirements 

Clean Air Act section 111, which 

Congress enacted as part of the 1970 

Clean Air Act Amendments, establishes 

mechanisms for controlling emissions of 

air pollutants from stationary sources. 

This provision requires the EPA to 

promulgate a list of categories of 

stationary sources that the 

Administrator, in his or her judgment, 

finds ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ 31 The EPA 

has listed more than 60 stationary 

source categories under this provision.32

Once the EPA lists a source category, 

the EPA must, under CAA section 

111(b)(1)(B), establish ‘‘standards of 

performance’’ for emissions of air 

pollutants from new sources in the 

source categories.33 These standards are 

known as new source performance 

standards (NSPS), and they are national 

requirements that apply directly to the 

sources subject to them. 

When the EPA establishes NSPS for 

new sources in a particular source 

category, the EPA is also required, 

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

prescribe regulations for states to submit 

plans regulating existing sources in that 

source category for any air pollutant 

that, in general, is not regulated under 

the CAA section 109 requirements for 

the NAAQS or regulated under the CAA 

section 112 requirements for hazardous 

air pollutants (HAP). CAA section 

111(d)’s mechanism for regulating 

existing sources differs from the one 

that CAA section 111(b) provides for 

new sources because CAA section 

111(d) contemplates states submitting 

plans that establish ‘‘standards of 

performance’’ for the affected sources 

and that contain other measures to 

implement and enforce those standards. 

‘‘Standards of performance’’ are 

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

standards for emissions that reflect the 

emission limitation achievable from the 

‘‘best system of emission reduction,’’ 

considering costs and other factors, that 

‘‘the Administrator determines has been 

adequately demonstrated.’’ CAA section 

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

applying a standard of performance to 

particular sources, to take into account 

the source’s remaining useful life or 

other factors. 

Under CAA section 111(d), a state 

must submit its plan to the EPA for 

approval, and the EPA must approve the 

state plan if it is ‘‘satisfactory.’’ 34 If a 

state does not submit a plan, or if the 

EPA does not approve a state’s plan, 

then the EPA must establish a plan for 

that state.35 Once a state receives the 

EPA’s approval for its plan, the 

provisions in the plan become federally 

enforceable against the entity 

responsible for noncompliance, in the 

same manner as the provisions of an 

approved SIP under CAA section 110. 

Although affected EGUs located in 

Indian country operate as part of the 

interconnected system of electricity 

production and distribution, those EGUs 

would not be encompassed within a 

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

a tribe that has one or more affected 

EGUs located in its area of Indian 

country 36 would have the opportunity, 

but not the obligation, to establish a 

plan that establishes standards of 

performance for CO2 emissions from 

affected EGUs for its tribal lands. 

The EPA issued regulations 

implementing CAA section 111(d) in 

1975,37 and has revised them in the 

years since.38 (We refer to the 

regulations generally as the 

implementing regulations, and we refer 

to the 1975 rulemaking as the 

framework regulations.) These 

regulations provide that, in 

promulgating requirements for sources 

under CAA section 111(d), the EPA first 

develops regulations known as 

‘‘emission guidelines,’’ which establish 

binding requirements that states must 

address when they develop their 

plans.39 The implementing regulations 

also establish timetables for state and 

EPA action: States must submit state 

plans within 9 months of the EPA’s 

issuance of the guidelines,40 and the 

EPA must take final action on the state 

plans within 4 months of the due date 

for those plans,41 although the EPA has 

authority to extend those deadlines.42 In 

the present rulemaking, the EPA is 

following the requirements of the 

implementing regulations, and is not reopening them, except that the EPA is 

extending the timetables, as described 

below. 

Over the last forty years, under CAA 

section 111(d), the agency has regulated 

four pollutants from five source 

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

mist), phosphate fertilizer plants 

(fluorides), primary aluminum plants 

(fluorides), Kraft pulp plants (total 

reduced sulfur), and municipal solid 

waste landfills (landfill gases)).43 In 

addition, the agency has regulated 

additional pollutants under CAA 

section 111(d) in conjunction with CAA 


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44See, e.g., ‘‘Standards of Performance for New 

Stationary Sources and Emission Guidelines for 

Existing Sources: Sewage Sludge Incineration Units, 

Final Rule,’’ 76 FR 15,372 (Mar. 21, 2011). 

45See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12,022 

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

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55,796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29,828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26,294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 F R 9905 (Mar. 12, 1996). 

46Presidential Memorandum—Power Sector 

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

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

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

section 129.44 The agency has not 

previously regulated CO2 or any other 

greenhouse gas under CAA section 

111(d). 

The EPA’s previous CAA section 

111(d) actions were necessarily geared 

toward the pollutants and industries 

regulated. Similarly, in this proposed 

rulemaking, in defining CAA section 

111(d) emission guidelines for the states 

and determining the BSER, the EPA 

believes that taking into account the 

particular characteristics of carbon 

pollution, the interconnected nature of 

the power sector and the manner in 

which EGUs are currently operated is 

warranted. Specifically, the operators 

themselves treat increments of 

generation as interchangeable between 

and among sources in a way that creates 

options for relying on varying 

utilization levels, lowering carbon 

generation, and reducing demand as 

components of the overall method for 

reducing CO2 emissions. Doing so 

results in a broader, forward-thinking 

approach to the design of programs to 

yield critical CO2 reductions that 

improve the overall power system by 

lowering the carbon intensity of power 

generation, while offering continued 

reliability and cost-effectiveness. These 

opportunities exist in the power sector 

in ways that were not relevant or 

available for other industries for which 

the EPA has established CAA section 

111(d) emission guidelines.45

In this action, the EPA is proposing 

emission guidelines for states to follow 

in developing their plans to reduce 

emissions of CO2 from the electric 

power sector. 

III. Stakeholder Outreach and 

Conclusions 

A. Stakeholder Outreach 

1. The President’s Call for Engagement 

Following the direction of the 

Presidential Memorandum to the 

Administrator (June 25, 2013),46 this 

proposed rule was developed after 

extensive and vigorous outreach to 

stakeholders and the general public. The 

Presidential Memorandum instructed 

the Administrator to inaugurate the 

process for developing standards 

through direct engagement with the 

states and a full range of stakeholders: 

Launch this effort through direct 

engagement with States, as they will play a 

central role in establishing and implementing 

standards for existing power plants, and, at 

the same time, with leaders in the power 

sector, labor leaders, non-governmental 

organizations, other experts, tribal officials, 

other stakeholders, and members of the 

public, on issues informing the design of the 

program. 

2. Educating the Public and Stakeholder 

Outreach 

To carry out this stakeholder 

outreach, the EPA embarked on an 

unprecedented pre-proposal outreach 

effort. From consumer groups to states 

to power plant owner/operators to 

technology innovators, the EPA sought 

input from all perspectives. 

The EPA began the outreach efforts 

with a webinar and associated 

teleconferences to establish a common 

understanding of the basic requirements 

and process of CAA section 111(d). The 

August 27, 2013 overview presentation 

was offered as a webinar for state and 

tribal officials, ‘‘Building a Common 

Understanding: Clean Air Act and 

Upcoming Carbon Pollution Guidelines 

for Existing Power Plants.’’ 

The EPA followed up on the 

presentation by offering four national 

teleconference calls with representatives 

from states, tribes, industry, 

environmental justice organizations, 

community organizations and 

environmental representatives. The 

teleconferences offered a venue for 

stakeholders to ask questions of the EPA 

about the overview presentation and for 

the EPA to gather initial reactions from 

stakeholders. Stakeholders and 

members of the public continued to 

view and refer to the overview 

presentation throughout the outreach 

process. By May 2014, the presentation 

had been viewed more than 5,600 times. 

The agency also provided 

mechanisms for anyone from the public 

to provide input during the pre-proposal 

development of this action. The EPA set 

up two user-friendly options to accept 

input during the pre-proposal period— 

email and a web-based form. The EPA 

has received more than 2,000 emails 

offering input into the development of 

these guidelines. 

These emails and other materials 

provided to the EPA are posted on line 

as part of a non-regulatory docket, EPA 

Docket ID No. EPA–HQ–OAR–2014– 

0020, at www.regulations.gov. All of the 

documents on which this proposal is 

based are available at Docket ID No. 

EPA–HQ–OAR–2013–0602, at 

www.regulations.gov. However, while 

the information collected through 

extensive outreach helped the agency 

formulate this proposal, we are not 

relying on all of the documents, emails, 

and other information included in the 

informational docket that was 

established as a part of that outreach 

effort, nor will the EPA be responding 

to specific comments or issues raised 

during the outreach effort. Rather, we 

have included in the docket for this 

proposal all of the information we relied 

on for this action. 

The agency has encouraged, 

organized, and participated in hundreds 

of meetings about CAA section 111(d) 

and reducing carbon pollution from 

existing power plants. Attendees at 

these various meetings have included 

states and tribes, members of the public, 

and representatives from multiple 

industries, labor leaders, environmental 

groups and other non-governmental 

organizations. The direct engagement 

has brought together a variety of states 

and stakeholders to discuss a wide 

range of issues related to the electricity 

sector and the development of emission 

guidelines under CAA section 111(d). 

The meetings occurred in Washington, 

DC, and at locations across the country. 

The meetings were attended by the EPA 

Regional Administrators, managers and 

staff and who are playing or will play 

key roles in developing and 

implementing the rule. 

Part of this effort included the 

agency’s holding of 11 public listening 

sessions; one national listening session 

in Washington, DC and 10 listening 

sessions in locations in the EPA regional 

offices across the country. All of the 

outreach meetings were designed to 

solicit policy ideas, concerns and 

technical information from stakeholders 

about using CAA section 111(d). 

This outreach process has produced a 

wealth of information which has 

informed this proposal significantly. 

The pre-proposal outreach efforts far 

exceeded what is required of the agency 

in the normal course of a rulemaking 

process, and the EPA expects that the 

dialog with states and stakeholders will 

continue throughout the process and 

even after the rule is finalized. The EPA 

recognizes the importance of working 

with all stakeholders, and in particular 

with the states, to ensure a clear and 

common understanding of the role the 


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states will play in addressing carbon 

pollution from power plants. 

3. Public Listening Sessions 

More than 3,300 people attended the 

public listening sessions held in 11 

cities across the country. Holding the 

listening sessions at the EPA’s regional 

offices offered thousands of people from 

different parts of the country the 

opportunity to provide input to EPA 

officials in accessible venues. In 

addition to being well located, holding 

the sessions in regional offices also 

allowed the agency to use resources 

prudently and enabled a variety of the 

EPA staff involved in the development 

and ultimate implementation of this 

upcoming rule to attend and learn from 

the views expressed. 

More than 1,600 people spoke at the 

11 listening sessions. Speakers included 

Members of Congress, other public 

officials, industry representatives, faithbased organizations, unions, 

environmental groups, community 

groups, students, public health groups, 

energy groups, academia and concerned 

citizens. Participants shared a range of 

perspectives. Many were concerned by 

the impacts of climate change on their 

health and on future generations, others 

worried about the impact of regulations 

on the economy. Their support for the 

agency’s efforts varied. 

Summaries of these 11 public 

listening sessions are available at 

www.regulations.gov at EPA Docket ID 

No. EPA–HQ–OAR–2014–0020. 

4. State Officials 

Since fall 2013, the agency provided 

multiple opportunities for the states to 

inform this proposal. In addition, the 

EPA organized, encouraged and 

attended meetings to discuss multi-state 

planning efforts. Because of the 

interconnectedness of the power sector, 

and the fact that electricity generated at 

power plants crosses state lines, states, 

utilities and ratepayers may benefit from 

states working together to address the 

requirements of this rulemaking 

implementation. The meetings provided 

state leaders, including governors, 

environmental commissioners, energy 

officers, public utility commissioners, 

and air directors, opportunities to 

engage with the EPA officials. 

Agency officials listened to ideas, 

concerns and details from states, 

including from states with a wide range 

of experience in reducing carbon 

pollution from power plants. The 

agency has collected policy papers from 

states with overarching energy goals and 

technical details on the states’ 

electricity sector. The agency has 

engaged, and will continue to engage 

with, all of the 50 states throughout the 

rulemaking process. 

5. Tribal Officials 

The EPA conducted significant 

outreach to tribes, who are not required 

to—but may—develop or adopt Clean 

Air Act programs. The EPA is aware of 

three coal-fired power plants and one 

natural gas-fired EGU located in Indian 

country but is not aware of any EGUs 

that are owned or operated by tribal 

entities. 

The EPA conducted outreach to tribal 

environmental staff and offered 

consultation with tribal officials in 

developing this action. Because the EPA 

is aware of tribal interest in this 

proposed rule, the EPA offered 

consultation with tribal officials early in 

the process of developing the proposed 

regulation to permit tribes to have 

meaningful and timely input into its 

development. 

The EPA sent consultation letters to 

584 tribal leaders. The letters provided 

information regarding the EPA’s 

development of emission guidelines for 

existing power plants and offered 

consultation. None have requested 

consultation. Tribes were invited to 

participate in the national informational 

webinar held August 27, 2013. In 

addition, a consultation/outreach 

meeting was held on September 9, 2013, 

with tribal representatives from some of 

the 584 tribes. The EPA representatives 

also met with tribal environmental staff 

with the National Tribal Air 

Association, by teleconference, on 

December 19, 2013. In those 

teleconferences, the EPA provided 

background information on the GHG 

emission guidelines to be developed 

and a summary of issues being explored 

by the agency. 

In addition, the EPA held a series of 

listening sessions prior to development 

of this proposed action. Tribes 

participated in a session on September 

9, 2013 with the state agencies, as well 

as in a separate session with tribes on 

September 26, 2013. 

6. Industry Representatives 

Agency officials have engaged with 

industry leaders and representatives 

from trade associations in scores of oneon-one and national meetings. Many 

meetings occurred at the EPA 

headquarters and in the EPA’s Regional 

Offices and some were sponsored by 

stakeholder groups. Because the focus of 

the standard is on the electricity sector, 

many of the meetings with industry 

have been with utilities and industry 

representatives directly related to the 

electricity sector. The agency has also 

met with energy industries such as coal 

and natural gas interests, as well as 

companies that offer new technology to 

prevent or reduce carbon pollution, 

including companies that have expertise 

in renewable energy and energy 

efficiency. Other meetings have been 

held with representatives of energy 

intensive industries, such as the iron 

and steel and aluminum industries to 

help understand the issues related to 

large industrial users of electricity. 

7. Electric Utility Representatives 

Agency officials participated in many 

meetings with utilities and their 

associations. The meetings focused on 

the importance of the utility industry in 

reducing carbon emissions from power 

plants. Power plant emissions are 

central to this rulemaking. The EPA 

encouraged industry representatives to 

work with state environmental and 

energy officers. 

The electric utility representatives 

included private utilities or investor 

owned utilities. Public utilities and 

cooperative utilities were also part of indepth conversations about CAA section 

111(d) with EPA officials. 

The conversations included meetings 

with the EPA headquarters and Regional 

offices. State officials were included in 

many of the meetings. Meetings with 

utility associations and groups of 

utilities were held with key EPA 

officials. The meetings covered 

technical, policy, and legal topics of 

interest and utilities expressed a wide 

variety of support and concerns about 

CAA section 111(d). 

8. Electricity Grid Operators 

The EPA had a number of 

conversations with the Independent 

System Operators and Regional 

Transmission Organizations (ISOs and 

RTOs) to discuss the rule and issues 

related to grid operations and reliability. 

EPA staff met with the ISO/RTO 

Council on several occasions to collect 

their ideas. The EPA Regional Offices 

also met with the ISOs and RTOs in 

their regions. System operators have 

offered suggestions in using regional 

approaches to implement CAA section 

111(d) while maintaining reliable, 

affordable electricity. 

9. Representatives From NonGovernmental Organizations 

Agency officials engaged with 

representatives of environmental justice 

organizations during the outreach effort, 

for example, we engaged with the 

National Environmental Justice 

Advisory Council members in 

September 2013. The NEJAC is 

composed of stakeholders, including 

environmental justice leaders and other 


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leaders from state and local government 

and the private sector. 

The EPA has also met with a number 

of environmental groups to provide 

their ideas on how to reduce carbon 

pollution from existing power plants 

using section 111(d) of the CAA. 

Many environmental organizations 

discussed the need for reducing carbon 

pollution. Meetings were technical, 

policy and legal in nature and many 

groups discussed specific state policies 

that are already in place to reduce 

carbon pollution in the states. 

A number of organizations 

representing religious groups have 

reached out to the EPA on several 

occasions to discuss their concerns and 

ideas regarding this rule. 

Public health groups discussed the 

need for protection of children’s health 

from harmful air pollution. Doctors and 

health care providers discussed the link 

between reducing carbon pollution and 

air pollution and public health. 

Consumer groups representing 

advocates for low income electricity 

customers discussed the need for 

affordable electricity. They talked about 

reducing electricity prices for 

consumers through energy efficiency 

and low cost carbon reductions. 

10. Labor 

EPA senior officials and staff met with 

a number of labor union representatives 

about reducing carbon pollution using 

CAA section 111(d). Those unions 

included: The United Mine Workers of 

America; the Sheet Metal, Air, Rail and 

Transportation Union (SMART); the 

International Brotherhood of 

Boilermakers, Iron Ship Builders, 

Blacksmiths, Forgers and Helpers (IBB); 

United Association of Journeymen and 

Apprentices of the Plumbing and Pipe 

Fitting Industry of the United States and 

Canada; the International Brotherhood 

of Electrical Workers (IBEW): And the 

Utility Workers Union of America. In 

addition, agency leaders met with the 

Presidents of several unions and the 

President of the American Federation of 

Labor-Congress of Industrial 

Organizations (AFL–CIO) at the AFL– 

CIO headquarters. 

EPA officials, when invited, attended 

meetings sponsored by labor unions to 

give presentations and engage in 

discussions about reducing carbon 

pollution using CAA section 111(d). 

These included meetings sponsored by 

the IBB and the IBEW. 

B. Key Messages From Stakeholders 

Many stakeholders stated that 

opportunities exist to reduce the carbon 

emissions from existing power 

generation through a wide range of 

measures, from measures that are 

implementable via physical changes at 

the source to those that also are 

implementable across the broader power 

generation system. Opinions varied 

about how broader system measures 

could factor into programs to reduce 

carbon pollution. Some stakeholders 

recommended that system-wide 

measures be allowed for compliance, 

but not factored into the carbon 

improvement goals the EPA establishes, 

while others recommended that systemwide measures be factored into the 

goals. Among the arguments and 

information offered by stakeholders who 

suggested that states be encouraged to 

incorporate system-wide measures into 

their state plans and that EGU operators 

be encouraged to rely on such measures 

were examples and discussions of the 

significant extent to which dispatch, 

end use energy efficiency and renewable 

energy had already proven to be 

successful strategies for reducing EGU 

CO2 emissions. Some state and industry 

representatives favored goals that they 

described as based on measures 

implementable only within the facility 

‘‘fence line’’ (i.e., measures 

implementable only at the source). 

Many stakeholders stated that the EPA 

should not require the state plans to 

impose on the affected EGUs legal 

responsibility for the full amount of 

required CO2 emissions reductions, and 

instead, the EPA should authorize the 

state plans to include requirements on 

entities other than the affected EGUs 

that would have the effect of reducing 

utilization and, therefore, emissions 

from the affected EGUs. 

Views on the form and stringency of 

the goal or guidelines varied. Some 

stakeholders preferred a rate-based form 

of the goal, while others preferred a 

mass-based form. In addition, some 

stakeholders recommended that the EPA 

let the states have the flexibility to 

either choose among multiple forms of 

the goals or to set their own goals. With 

regard to the stringency of the goal, 

some stakeholders recommended that 

the stringency of the goals vary by state, 

to account for differences in state 

circumstances. 

Many stakeholders recognized the 

value of allowing states flexibility in 

implementing the goals the EPA 

establishes. For example, states 

highlighted the importance of the EPA 

recognizing existing state and regional 

programs that address carbon pollution, 

including market-based programs, and 

allowing credit for prior 

accomplishments in reducing CO2

emissions. Many states and other 

stakeholders noted the importance of 

the EPA allowing flexibility in 

compliance options such that states 

could use approaches such as demandside management to attain the goals. 

Many stakeholders recommended that 

states be allowed to develop multi-state 

programs. It was frequently noted that 

such regional approaches could offer 

cost-effective carbon pollution 

solutions. 

There was broad agreement that most 

states would need more than one year 

to develop and submit their complete 

plans to the EPA. For some states, more 

time is necessary because of the state 

legislative schedule and/or regulatory 

process. In some cases, approval of a 

plan through a state’s legislative or 

regulatory process could take one year 

or more after the plan has already been 

developed. Additional time would also 

allow and encourage multi-state and 

regional partnerships and programs. 

Many stakeholders also supported 

flexibility in the timing of 

implementation of the state plans and 

power sector compliance with the goals 

in the state plans. Such flexibility, some 

stakeholders asserted, would 

accommodate the diverse GHG 

mitigation potential of states and 

support more cost-effective approaches 

to achieving CO2 reductions. 

During the outreach process, some 

stakeholders raised general concerns 

that the rulemaking could have a 

negative impact on jobs and ratepayers. 

Some stakeholders also expressed 

concerns about potential adverse effects 

on electric system reliability. Some 

stakeholders were concerned that 

meeting the goals could potentially 

result in stranded generation assets. To 

prevent this from occurring, some 

stakeholders suggested varying the 

stringency of standards to account for 

individual state circumstances and 

variation. 

The EPA has given stakeholder input 

careful consideration during the 

development of this proposal and, as a 

result, this proposal includes features 

that are intended to be responsive to 

many stakeholder concerns. 

C. Key Stakeholder Proposals 

During the EPA’s public outreach in 

advance of this proposal, a number of 

ideas were put forward that are not fully 

reflected in this proposal. We invite 

public comment on these ideas, some of 

which are outlined below. 

1. Model Rule on Interstate Emissions 

Credit Trading and Price Ceiling 

Some groups thought that the EPA 

should put forward a model rule for an 

interstate emissions credit trading 

program that could be easily adopted by 

states who wanted to use such a 


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47The nine states include Connecticut, Delaware, 

Maine, Maryland, Massachusetts, New Hampshire, 

New York, Rhode Island, and Vermont. 

48Regional Greenhouse Gas Initiative 2013 

Allowance Allocation http://rggi.org/design/

overview/allowance-allocation/2013-allocation. 

49Regional Investments of RGGI CO2 Allowance 

Proceeds, 2012 (2014), available at http://

www.rggi.org/docs/Documents/2012-InvestmentReport.pdf. 

50Of the $707 million in auction proceeds 

invested by RGGI participating states through 2012, 

65 percent supported end-use energy efficiency 

programs. See Regional Greenhouse Gas Initiative, 

‘‘Regional Investments of RGGI CO2 Allowance 

Proceeds, 2012’’ (2014). Available at http://

www.rggi.org/docs/Documents/2012-InvestmentReport.pdf. 

51 Id. 

52Regional Greenhouse Gas Initiative, Report on 

Emission Reduction Efforts of the States 

Participating in the Regional Greenhouse Gas 

Initiative and Recommendations for Guidelines 

under Section 111(d) of the Clean Air Act (2013). 

53The first three-year control period under RGGI, 

establishing CO2 emission limits for EGUs, began on 

January 1, 2009. 

54RGGI Press Release, January 13, 2014, http://

www.rggi.org/docs/PressReleases/PR011314_

AuctionNotice23.pdf. 

55State of California Global Warming Solutions 

Act of 2006, Assembly Bill 32, Chapter http://

www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001- 

0050/ab_32_bill_20060927_chaptered.pdf. 

56Preliminary California Air Resources Board 

analyses, based in part on CARB 2008 to 2012 

Emissions for Mandatory GHG reporting Summary 

(2013), cited in Letter to the EPA Administrator, 

‘‘States’ Roadmap on Reducing Carbon Pollution,’’ 

December 16, 2013. Available at http://

www.georgetownclimate.org/sites/default/files/

EPA_Submission_from_States-FinalCompl.pdf. 

program for its plan. One group 

suggested the model rule should include 

a provision to allow the state to 

compensate merchant generators as well 

as retail rate payers. Another group 

specified that the model rule would also 

include a ceiling-price called an 

alternative compliance payment that 

would fund state directed clean 

technology investment. Facilities that 

face costs that exceed the ceiling price 

could opt to pay into the fund as a way 

of complying. 

2. Equivalency Tests 

One group recommended that state 

programs be allowed to demonstrate 

equivalency using one of three tests: 

Rate-based equivalency via a 

demonstration that the state program 

achieves equivalent or better carbon 

intensity for the regulated sector; massbased equivalency via a demonstration 

that the program achieves equal or 

greater emission reductions relative to 

what would be achieved by the federal 

approach; or a market price-based 

equivalency via a demonstration that 

the program reflects a carbon price 

comparable to or greater than the costeffectiveness benchmark used by the 

EPA in designing the program. The EPA 

is proposing a way to demonstrate 

equivalency and that is discussed in 

Section VIII of this preamble. 

3. Power Plant-Specific Assessment 

Other stakeholders suggested that an 

‘‘inside the fence’’ plant- or unit-specific 

assessment linked to the availability of 

control at the source such as heat rate 

improvements should be considered. 

They indicated that once plant-specific 

goals are established based on on-site 

CO2 reduction opportunities, the source 

should have the flexibility to look 

‘‘outside the fence’’ for the means to 

achieve the goals, including the use of 

emissions trading, and averaging. 

The EPA invites comment on these 

suggestions. 

D. Consideration of the Range of 

Existing State Policies and Programs 

Across the nation, many states and 

regions have shown strong leadership in 

creating and implementing policies and 

programs that reduce GHG emissions 

from the power sector while achieving 

other economic, environmental, and 

energy benefits. Some of these activities, 

such as market-based programs and 

GHG performance standards, directly 

require GHG emission reductions from 

EGUs. Others reduce GHG emissions by 

reducing utilization of fossil fuel-fired 

EGUs through, for example, renewable 

portfolio standards (RPS) and energy 

efficiency resource standards (EERS), 

which alter the mix of energy supply 

and reduce energy demand. States have 

developed their policies and programs 

with stakeholder input and tailored 

them to their own circumstances and 

priorities. Their leadership and 

experiences provided the EPA with 

important information about best 

practices to build upon in this proposed 

rule. As directed by the Presidential 

Memorandum, the EPA is, with this 

proposal to reduce power plant carbon 

pollution, building on actions already 

underway in states and the power 

sector. 

1. Market-Based Emission Limits 

Nine states actively participate in the 

Regional Greenhouse Gas Initiative 

(RGGI), a market-based CO2 emission 

reduction program addressing EGUs that 

was established in 2009.47 Through 

RGGI, the participating states are 

implementing coordinated CO2

emission budget trading programs. In 

aggregate, these programs establish an 

overall limit on allowable CO2

emissions from affected EGUs in the 

participating states. Participating states 

issue CO2 allowances in an amount up 

to the number of allowances in each 

state’s annual emission budget. At the 

end of each three-year compliance 

period, affected EGUs must submit CO2

allowances equal to their reported CO2

emissions. CO2 allowances may be 

traded among both regulated and nonregulated parties, creating a market for 

emission allowances. This market 

creates a price signal for CO2 emissions, 

which factors into the dispatch of 

affected EGUs. A price signal for CO2

emissions also allows sources flexibility 

to make emission reductions where 

reduction costs are lowest, and 

encourages innovation in developing 

emission control strategies. 

Approximately 90 percent of CO2

allowances are distributed by the RGGI 

participating states through auction.48

From 2009 through 2012, the nine RGGI 

states invested auction proceeds of more 

than $700 million in programs that 

lower costs for energy consumers and 

reduce CO2 emissions.49 Through 2012, 

for example, the RGGI states invested 

approximately $460 million of proceeds 

into energy efficiency programs.50 The 

participating RGGI states estimate that 

those investments are providing benefits 

to energy consumers in the region of 

more than $1.8 billion in lifetime energy 

savings.51

Between 2005, when an agreement to 

implement RGGI was announced, and 

2012, power sector CO2 emissions in the 

RGGI participating states fell by more 

than 40 percent.52 RGGI was not the 

primary driver for these reductions but 

the reductions led RGGI-participating 

states to later adjust the CO2 emission 

limits downward.53 In January 2014, the 

participating states lowered the overall 

allowable CO2 emission level in 2014 by 

45 percent, setting a multi-state CO2

emission limit for affected EGUs of 91 

million short tons of CO2 in 2014 and 

78 million short tons of CO2 in 2020, 

more than 50 percent below 2008 

levels.54

Similarly, California established an 

economy-wide market-based GHG 

emissions trading program under the 

authority of its 2006 Global Warming 

Solutions Act, which requires the state 

to reduce its 2020 GHG emissions to 

1990 levels.55 While California’s 

emission trading program, like its state 

emission limit, is multi-sector in scope, 

the state projects that the emissions 

trading program and related 

complementary measures will reduce 

power sector GHG emissions to less 

than 80 million metric tons of CO2

equivalent by 2025, a 25 percent 

reduction from 2005 power sector 

emission levels.56 Prior to the 

implementation of the emission trading 

program, California reports that it 

reduced CO2 power sector emissions by 

16 percent from 2005 to a 2010–2012 


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57 Id. 

58 6 New York Codes, Rules & Regulations. Part 

251 (Adopted June 28, 2012). 

59OR SB 101 (2000); Washington Revised Code 

ch.80.80 (2013); Wash SB 6001 (2007). 

60Colorado Clean Air, Clean Jobs Act, HB1365. 

61 Xcel Energy, Colorado Clean Air-Clean Jobs 

Plan, available at http://www.xcelenergy.com/

Environment/Doing_Our_Part/Clean_Air_Projects/

Colorado_Clean_Air_Clean_Jobs_Plan. 

62http://www.dsireusa.org/. 

63Report to the Minnesota Legislature: Progress 

on Compliance By Electric Utilities With The 

Minnesota Renewable Energy Objective and the 

Renewable Energy Standard, Prepared by: The 

Minnesota Department of Commerce, Division of 

Energy Resources January 14, 2013; http://mn.gov/ 

commerce/energy/images/2013RESLegReport.pdf. 

64 Id. 

65Minnesota Statutes 2013, Section 216B.1691, 

Subdivision 2f. Solar Energy Standard https://

www.revisor.mn.gov/statutes/?id=216b.1691. 66Eugene Water Electric Board Oregon 

Renewable Portfolio Standard 2012 Compliance 

Report and 2013–2030 Implementation Plan, June 1, 

2013. PacifiCorp’s Renewable Portfolio Standard 

Oregon Compliance Report for 2012, May 31, 2013. 

PGE 2012 Renewable Portfolio Standard 

Compliance Report, June 1, 2013. 

averaging period, a reduction of 16 

million metric tons of CO2 equivalent.57

2. GHG Performance Standards 

Four states, California, New York, 

Oregon and Washington, have enacted 

GHG emission standards that impose 

enforceable emission limits on new and/ 

or expanded electric generating units. 

For example, since 2012, New York 

requires new or expanded baseload 

plants that are greater than 25 

Megawatts (MW) to meet an emission 

rate of either 925 pounds CO2/Megawatt 

hour (MWh) (based on output) or 120 

pounds of CO2/Million British Thermal 

Units (MMBtu) (based on input). 

Similarly, non-baseload plants in New 

York of at least 25 MW or larger must 

meet an emission rate of either 1450 

pounds CO2/MWh (based on output) or 

160 pounds of CO2/MMBtu (based on 

input).58

Three states, California, Oregon and 

Washington, have enacted GHG 

emission performance standards that set 

an emission rate for electricity 

purchased by electric utilities. In both 

Oregon and Washington, for example, 

electric utilities may enter into long 

term power purchase agreements for 

baseload power only if the electric 

generator supplying the power has a 

CO2 emission rate of 1,100 pounds of 

CO2 per MWh or less.59

3. Utility Planning Approaches 

Two states, Minnesota and Colorado, 

have worked collaboratively with their 

investor-owned utilities to develop 

multi-pollutant emission reduction 

plans on a utility-wide basis. This 

multi-pollutant, collaborative approach 

enables utilities to determine the least 

cost way to meet long term and 

comprehensive energy and 

environmental goals. 

Colorado’s Clean Air, Clean Jobs Act 

of 2010, for example, required Colorado 

investor-owned utilities with coal plants 

to develop a multi-pollutant plan to 

meet existing and reasonably 

foreseeable federal CAA requirements.60

The utilities were not required to adopt 

a specific plan set by the state but were, 

instead, required to work collaboratively 

with the Colorado Department of Public 

Health and Environmental and Colorado 

Public Utility Commission to develop 

an acceptable plan. Xcel Energy, 

Colorado’s largest investor-owned 

utility, submitted a plan that was 

approved in 2010. With this plan, Xcel 

Energy is projected to reduce its CO2

emissions from generation in Colorado 

by 28 percent by 2020.61

4. Renewable Portfolio Standards 

More than 25 states have mandatory 

renewable portfolio standards that 

require retail electricity suppliers to 

supply a minimum percentage or 

amount of their retail electricity load 

with electricity generated from eligible 

sources of renewable energy.62 These 

standards have been established via 

utility regulatory commissions, 

legislatures and citizen ballots and 

requirements vary from state to state. 

State RPS typically specify the types of 

renewable energy, or other energy 

sources, that qualify for use toward 

achievement of the standard, and often 

allow for the use of qualifying 

renewable energy resources located 

outside of the state. They reduce 

utilization of fossil fuel-fired EGUs and, 

thereby, lead to reductions in GHG 

emissions by meeting a portion of the 

demand for electricity through 

renewable or other energy sources. 

In 2007, the Minnesota legislature 

amended the state’s 2001 renewable 

energy objective and established a 

renewable energy standard (RES) 

requiring at least 25 percent of all 

electricity generated or purchased in 

Minnesota to come from renewable 

energy by 2025. The standard sets 

requirements and timetables, beginning 

in 2010, that vary based on the provider. 

For example, in 2011, Xcel Energy had 

a requirement to generate or purchase 

15 percent of its total retail sales from 

renewable energy while all other 

utilities had a target of 7 percent of total 

retail sales. According to the latest 

Minnesota Department of Commerce 

report to the legislature on progress, all 

utilities subject to the standard met it 

for 2011 and were on track to meet their 

2012 goals.63 The 2012 requirement 

increased to 18 percent of total retail 

sales for Xcel Energy and 12 percent for 

all other utilities.64 In 2013, the 

Minnesota legislature expanded the RES 

with solar incentives and a specific 

solar energy standard requiring 

Minnesota utilities to ensure that at 

least 1.5 percent of their retail electricity 

sales in 2020 come from solar energy.65

The Oregon Renewable Portfolio 

Standard (RPS) is another example of a 

state requirement for renewables. 

Originally enacted in 2007, it requires 

that all utilities serving Oregon meet a 

percentage of their retail electricity 

needs with qualified renewable 

resources. Like in Minnesota, the 

percentage varies across utilities with 

the three largest utilities required to 

reach five percent from renewable 

energy sources starting in 2011, 15 

percent in 2015, 20 percent in 2020, and 

25 percent in 2025. Other electric 

utilities in the state are required to reach 

levels of five percent or ten percent by 

2025, depending on their size. 

According to the latest RPS compliance 

reports submitted by the largest utilities 

for the state, each had achieved the five 

percent target as of the end of 2012.66

5. Demand-Side Energy Efficiency 

Programs 

Many electric utilities, third-party 

administrators, and states implement 

demand-side energy efficiency programs 

to reduce generation from EGUs by 

reducing electricity use, including peak 

demand. When these programs reduce 

fossil fuel electricity generation, they 

also reduce CO2 emissions. Demandside energy efficiency programs use a 

variety of energy efficiency measures to 

target a variety of end uses and are often 

driven by existing state standards and 

programs, such as policies requiring 

utilities to obtain ‘‘all cost-effective 

energy efficiency’’ through long-term 

integrated resource planning (IRP), 

renewable portfolio standards (RPS) that 

include efficiency as a qualifying 

resource, energy efficiency resource 

standards (EERS), public benefit funds, 

and other demand-side planning 

requirements. 

The purposes of demand-side energy 

efficiency programs vary; goals include 

to reduce GHG emissions by reducing 

fossil-fired generation, help states 

achieve energy savings goals, save 

energy and money for consumers and 

improve electricity reliability. They are 

typically funded through a small fee or 

surcharge on customer electricity bills, 

but can also be funded by other sources, 

such as from RGGI CO2 allowance 

auction proceeds mentioned above. 


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67Consortium for Energy Efficiency Annual 

Industry Report: 2013 State of the Efficiency 

Program Industry—Budgets, Expenditures and 

Impacts, 2014. 

68Lawrence Berkeley National Laboratory (LBNL) 

The Future of Utility Customer-Funded Energy 

Efficiency Programs in the United States: Projected 

Spending and Savings to 2025 (http://emp.lbl.gov/ 

sites/all/files/lbnl-5803e.pdf). 

69American Council for an Energy Efficient 

Economy (ACEEE) 2013 State Scorecard http://

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

researchreports/e13k.pdf. 

70 December 27, 2013 Letter from Mary D. 

Nichols, Chairman of California Air Resources 

Board, to EPA Administrator Gina McCarthy. 

71Cal Pub. Utility Code § 454.5 (a)(9)(C). 

72Cited in December 27, 2013 Letter from Mary 

D. Nichols, Chairman of California Air Resources 

Board, to EPA Administrator Gina McCarthy. 

73 Id. 

74 Id. 

75State of Vermont Public Service Board, Energy 

Efficiency Utility Creation and Structure. http://

psb.vermont.gov/utilityindustries/eeu/generalinfo/ 

creationandstructure. 

76 Vermont Statute, Title 30: Public Service, 30 

V.S.A. § 209 (d)3(B). http://www.leg.state.vt.us/

statutes/fullsection.cfm?Title=30&Chapter=005&

Section=00209. 

77Efficiency Vermont Savings Claim Summary 

2013, Reported to the Vermont Public Service Board 

and to the Vermont Public Service Department, 

2014, https://www.efficiencyvermont.com/docs/

about_efficiency_vermont/annual_summaries/

2013_savingsclaim_summary.pdf. 

78 Id. 

79State Energy Efficiency Resource Standards: 

Policy Design, Status, and Impacts, DC Steinberg, O. 

Zinaman, NREL Technical Report NREL/TP–6A20– 

61023, April 2014. 

80Arizona Corporation Commission, Docket RE– 

OOOOOC–09–0427, August 2010. Available at 

http://images.edocket.azcc.gov/docketpdf/00001

16125.pdf. 

81 Id. 82Arizona Corporation Commission, Docket RE– 

OOOOOC–09–0427, August 2010. Available at 

http://images.edocket.azcc.gov/docketpdf/0000

116125.pdf. 83 Id. 84Arizona Public Service Company 2012 Demand 

Side Management Annual Progress Report, March 1, 

2013 Web site, http://www.aps.com/en/

ourcompany/aboutus/energyefficiency/Pages/

home.aspx. 

Nationally, total spending on electric 

ratepayer-funded energy efficiency 

programs was about $5 billion in 

2012.67 Based on Lawrence Berkeley 

National Laboratory (LBNL) projections, 

spending is projected to reach $8.1 

billion in 2025.68

Electricity savings from energy 

efficiency programs are also growing. In 

2011, electricity savings from these 

programs totaled approximately 22.9 

million MWh, a 22 percent increase 

from the previous year.69

California has been advancing energy 

efficiency through utility-run demandside energy efficiency programs for 

decades and considers energy efficiency 

‘‘the bedrock upon which climate 

policies are built.’’ 70 It requires its 

investor-owned utilities to meet 

electricity load ‘‘through all available 

energy efficiency and demand reduction 

resources that are cost-effective, reliable 

and feasible.’’ 71 The California Public 

Utility Commission works with the 

California Energy Commission to 

determine the amount of cost-effective 

reduction potential and establishes 

efficiency targets. A recent energy 

efficiency potential study found that, 

even after years of running programs, 

California can still tap ‘‘tens of 

thousands of GWh in potential savings 

. . . over the next decade.’’ 72 Investorowned utilities use demand-side energy 

efficiency programs to achieve their 

targets and currently ‘‘save about 3,000 

GW per year, enough savings to power 

about 600,000 households.’’ 73 Between 

2010 and 2011, these programs are 

estimated to have reduced CO2 by 3.8 

million tons.74

In Vermont, for example, the Vermont 

Legislature and the Vermont Public 

Service Board (PSB) established the first 

statewide ‘‘energy efficiency utility’’ in 

1999 to provide energy efficiency 

services to residences and businesses 

throughout the state.75 Vermont law 

requires that the energy efficiency 

utility budgets be set at a level to 

achieve ‘‘all reasonably available, costeffective energy efficiency’’ and then 

specific energy (kWh) and peak demand 

(kW) savings levels are negotiated every 

three years.76 In 2013, Efficiency 

Vermont, the PSB-appointed energy 

efficiency utility, achieved annual 

savings of 1.66 percent of the state’s 

electricity sales, at a cost of 4.1 cents per 

kilowatt-hour, lower than the cost of 

comparable electric supply in the same 

year, which was 8.4 cents per kWh.77

Efficiency Vermont projects a net 

lifetime economic value to Vermont of 

more than $60 million from the 2013 

energy efficiency investments.78

6. Energy Efficiency Resource Standards 

More than 20 states have energy 

efficiency resource standards (EERS) 

that require utilities to save a certain 

amount of energy each year or 

cumulatively.79 They are typically 

multi-year requirements expressed as a 

percentage of annual retail electricity 

sales or as specific electricity savings 

amounts over a long term period relative 

to a baseline of retail sales. Over the 

compliance period, an EERS reduces 

fossil fuel-fired EGU generation through 

reductions in electricity demand, 

thereby reducing CO2 emissions from 

the power sector. 

In Arizona, for example, the Arizona 

Corporation Commission (ACC) adopted 

rules in 2010 requiring all investorowned utilities to achieve 22 percent 

cumulative electricity savings by 2020, 

making it one of the highest standards 

in the nation.80 The rule required 

utilities to achieve 1.25 percent 

electricity savings in 2011 compared to 

electricity sales in the previous year, 

ramping up the savings each year until 

2020 according to a designated 

timetable.81 In 2012, for example, 

investor-owned utilities were required 

to achieve energy savings equivalent to 

1.75 percent of the 2011 sales, leading 

to a cumulative savings requirement of 

3 percent by the end of 2012 (an average 

of 1.5% annually over the 2 year 

period).82 Utilities can meet the energy 

savings requirements through a variety 

of means, including cost-effective 

energy efficiency programs, as well as 

load management and demand response 

programs.83 Arizona Public Service 

Company (APS), the largest utility in 

Arizona, achieved cumulative energy 

savings equivalent to 3.2 percent of 

retail sales from 2011 to 2012, exceeding 

the 3 percent savings target, and 

reported a net benefit to consumers of 

more than $200 million for the year 

2012 alone.84

E. Conclusions 

States have taken a leadership role in 

mitigating GHG emissions and have 

demonstrated the potential for national 

application of a number of approaches. 

Throughout the development of this 

proposed rule, the EPA considered the 

states’ experiences and lessons learned 

regarding the design and 

implementation of successful GHG 

mitigation programs. The agency also 

fully considered input from 

stakeholders during the development of 

this proposed rulemaking. 

Considering all input from 

stakeholders, the agency recognizes that 

the most cost-effective approach to 

reducing GHG emissions from the 

power sector under CAA section 111(d) 

is to follow the lead of numerous states 

and not only to identify improvements 

in the efficiency of fossil fuel-fired 

EGUs as a component of the BSER, but 

also include in the BSER determination 

the EGU-emissions-reduction 

opportunities that states have already 

demonstrated to be successful in relying 

on lower- and zero-emitting generation 

and reduced electricity demand. 

CAA section 111(d) sets up a 

partnership between the EPA and the 

states. In the context of that partnership, 

the EPA recognizes the importance of 

each state having the flexibility to 

design a cost-effective program tailored 

to its own specific circumstances. The 

agency also recognizes, as many states 


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have, the value of regional planning in 

designing approaches to achieve costeffective GHG reductions. To support 

state flexibility and encourage multistate coordination in the development of 

multi-state and regional programs and 

policies, the EPA recognizes that 

flexibility in both the timing of plan 

submittal and the timing of CO2

emission reductions will be necessary. 

IV. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

The EPA is proposing emission 

guidelines for each state to use in 

developing plans to address greenhouse 

gas emissions from existing fossil fuelfired electric generating units. The 

emission guidelines are based on the 

EPA’s determination of the ‘‘best system 

of emission reduction . . . adequately 

demonstrated’’ (BSER) and include 

state-specific goals, general 

approvability criteria for state plans, 

requirements for state plan components, 

and requirements for the process and 

timing for state plan submittal and 

compliance. 

Under CAA section 111(d), the states 

must establish standards of performance 

that reflect the degree of emission 

limitation achievable through the 

application of the ‘‘best system of 

emission reduction’’ that, taking into 

account the cost of achieving such 

reduction and any non-air quality health 

and environmental impact and energy 

requirements, the Administrator 

determines has been adequately 

demonstrated. Consistent with CAA 

section 111(d), the EPA is proposing 

state-specific goals that reflect the EPA’s 

calculation of the BSER. 

Under CAA section 111(d), each state 

must develop, adopt, and then submit 

its plan to the EPA. To do so, the state 

would determine, and include in its 

plan, an emission performance level 

that is equivalent to the state-specific 

CO2 goal in the emission guidelines. As 

part of determining this level, the state 

would decide whether to adopt the ratebased form of the goal established by the 

EPA or translate the rate-based goal to 

a mass-based goal. The state would then 

establish a standard of performance or 

set of standards of performance (known 

as emission standards under the existing 

CAA section 111(d) framework 

regulations), along with implementing 

and enforcing measures, that will 

achieve a level of emission performance 

that equals or exceeds the level 

specified in the state plan. 

The EPA is proposing to determine 

the BSER as the combination of 

emission rate improvements and 

limitations on overall emissions at 

affected EGUs that can be accomplished 

through any combination of one or more 

measures from the following four sets of 

measures or building blocks: 

1. Reducing the carbon intensity of 

generation at individual affected EGUs 

through heat rate improvements. 

2. Reducing emissions from the most 

carbon-intensive affected EGUs in the 

amount that results from substituting 

generation at those EGUs with 

generation from less carbon-intensive 

affected EGUs (including natural gas 

combined cycle (NGCC) units that are 

under construction). 

3. Reducing emissions from affected 

EGUs in the amount that results from 

substituting generation at those EGUs 

with expanded low- or zero-carbon 

generation. 

4. Reducing emissions from affected 

EGUs in the amount that results from 

the use of demand-side energy 

efficiency that reduces the amount of 

generation required. 

The EPA has reviewed information 

about the current and recent 

performance of affected EGUs and 

states’ implementation of programs that 

reduce CO2 emissions from these 

sources. Based on our analysis of that 

information, the proposed state goals 

reflect the following stringency of 

application of the measures in each of 

the building blocks: Block 1, improving 

average heat rate of coal-fired steam 

EGUs by six percent; block 2, displacing 

coal-fired steam and oil/gas-fired steam 

generation in each state by increasing 

generation from existing NGCC capacity 

in that state toward a 70 percent target 

utilization rate; block 3, including the 

projected amounts of generation 

achievable by completing all nuclear 

units currently under construction, 

avoiding retirement of about six percent 

of existing nuclear capacity, and 

increasing renewable electric generating 

capacity over time through the use of 

state-level renewable generation targets 

consistent with renewable generation 

portfolio standards that have been 

established by states in the same region; 

and block 4, increasing state demandside energy efficiency efforts to reach 

1.5 percent annual electricity savings in 

the 2020–2029 period. 

Based on the EPA’s application of the 

BSER to each state, the EPA is 

proposing to establish, as part of the 

emission guidelines, state-specific goals, 

expressed as average emission rates for 

fossil fuel-fired EGUs. Each state’s goals 

comprise the EPA’s determination of the 

emission limitation achievable through 

application of the BSER in that state. 

For each state, the EPA is proposing an 

interim goal for the phase-in period 

from 2020 to 2029 and the final goal that 

applies beginning in 2030. The 

proposed goals for each state are listed 

in Section VII, below. The EPA is 

proposing that measures that a state 

takes after the date of this proposal, and 

that result in CO2 emission reductions 

during the plan period, would apply 

toward achievement of the state’s CO2

goal. 

The EPA is further proposing, as part 

of the plan guidelines, timetables for 

states to submit their plans. The agency 

expects to finalize this rulemaking by 

June 2015, and we are proposing to 

require that each state submit its plan to 

the EPA by June 30, 2016. However, if 

a state needs additional time to submit 

a complete plan, the state must submit 

an initial plan by June 30, 2016, that 

documents the reasons why more time 

is needed to submit a complete plan and 

includes commitments to take concrete 

steps that will ensure that the state will 

submit a complete plan by June 30, 

2017, or June 30, 2018, as appropriate. 

If such a state is developing a plan 

limited in geographical scope to the 

individual state, then the state would 

have until June 30, 2017, to submit a 

complete plan. A state that is 

developing a plan that includes a multistate approach would have until June 

30, 2018, to submit a complete plan. 

The EPA is further proposing, as part 

of the emission guidelines, to allow 

states the option of translating the EPAdetermined goal, which will be ratebased, to a mass-based goal. For states 

participating in a multi-state approach, 

the individual state performance goals 

in the emission guidelines would be 

replaced with an equivalent multi-state 

performance goal. The EPA is also 

proposing that in their plans, whether 

single state or multi-state, states may not 

adjust the stringency of the goals set by 

the EPA. 

Under CAA section 111(d)(1) and the 

implementing regulations, with the state 

emission performance level in place, the 

state must adopt a state plan that 

establishes a standard of performance or 

set of standards of performance, along 

with implementing and enforcing 

measures, that will achieve that 

emission performance level. The EPA is 

further proposing, as part of the 

guidelines, to authorize the state to 

submit either of two types of measures 

to achieve the performance level: (1) A 

set of measures that we refer to as 

‘‘portfolio’’ measures, which include a 

combination of emission limitations that 

apply directly to the affected sources 

and other measures that have the effect 

of limiting generation by, and therefore 

emissions from, the affected sources; or 

(2) solely emission limitations that 

apply directly to the affected sources. 


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85The EPA is aware of at least four affected EGUs 

located in Indian country: Two on Navajo lands, the 

Navajo Generating Station and the Four Corners 

Generating Station; one on Ute lands, the Bonanza 

Generating Station; and one on Fort Mojave lands, 

the South Point Energy Center. The affected EGUs 

at the first three plants are coal-fired EGUs. The 

fourth affected EGU is an NGCC facility. 

86The EPA is not re-opening that interpretation 

in this rulemaking. 

The EPA is also proposing, as part of 

the plan guidelines, that a complete 

state plan include the following twelve 

components: 

• Identification of affected entities 

• Description of plan approach and 

geographic scope 

• Identification of state emission 

performance level 

• Demonstration that plan is projected 

to achieve emission performance level 

• Identification of emissions standards 

• Demonstration that each emissions 

standard is quantifiable, nonduplicative, permanent, verifiable, 

and enforceable 

• Identification of monitoring, 

reporting, and recordkeeping 

requirements 

• Description of state reporting 

• Identification of milestones 

• Identification of backstop measures 

• Certification of hearing on state plan 

• Supporting material 

The EPA is also proposing, as part of 

its emission guidelines, that plan 

approvability be based on four general 

criteria: (1) Enforceable measures that 

reduce EGU CO2 emissions; (2) 

projected achievement of emission 

performance equivalent to the goals 

established by the EPA, on a timeline 

equivalent to that in the emission 

guidelines; (3) quantifiable and 

verifiable emission reductions; and (4) a 

process for reporting on plan 

implementation, progress toward 

achieving CO2 goals, and 

implementation of corrective actions, if 

necessary. 

The EPA is also proposing, as part of 

its plan guidelines, requirements for the 

process and timing for demonstrating 

achievement of the required emission 

performance level, including 

performance and emission milestones. 

The proposed option would require 

each state to achieve its ultimate CO2

emission performance level by 2030 

and, in addition, provide an initial, 

phase-in compliance period of up to 10 

years, from 2020 up to 2029, for a state 

and/or other responsible parties to 

comply with the emission performance 

level in the state plan. A state would 

need to meet its interim 2020–2029 CO2

emission performance level on average 

over the 10-year phase-in compliance 

period, achieve its final CO2 emission 

performance level by 2030, and 

maintain it thereafter. 

If a state with affected EGUs does not 

submit a plan or if the EPA does not 

approve a state’s plan, then under CAA 

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

establish a plan for that state. A state 

that has no affected EGUs must 

document this in a formal letter 

submitted to the EPA by June 30, 2016. 

In the case of a tribe that has one or 

more affected EGUs in its area of Indian 

country,85 the tribe would have the 

opportunity, but not the obligation, to 

establish a CO2 emission performance 

standard and a CAA section 111(d) plan 

for its area of Indian country. If it 

determines that such a plan is necessary 

or appropriate, the EPA has the 

responsibility to establish CAA section 

111(d) plans for areas of Indian country 

where affected sources are located 

unless a tribe on whose lands an 

affected source (or sources) is located 

seeks and obtains authority from the 

EPA to establish a plan itself, pursuant 

to the Tribal Authority Rule. 

B. Summary of Legal Basis 

This proposed action is consistent 

with the requirements of CAA section 

111(d) and the implementing 

regulations. As an initial matter, the 

EPA reasonably interprets the 

provisions identifying which air 

pollutants are covered under CAA 

section 111(d) to authorize the EPA to 

regulate CO2 from fossil fuel-fired EGUs. 

In addition, the EPA recognizes that 

CAA section 111(d) applies to sources 

that, if they were new sources, would be 

covered under a CAA section 111(b) 

rule. The EPA intends to complete two 

CAA section 111(b) rulemakings 

regulating CO2 from new fossil fuel-fired 

EGUs and from modified and 

reconstructed fossil fuel-fired EGUs 

before it finalizes this rulemaking, and 

either of those section 111(b) 

rulemakings will provide the requisite 

predicate for this rulemaking. 

A key step in promulgating 

requirements under CAA section 111(d) 

is determining the ‘‘best system of 

emission reduction . . . adequately 

demonstrated’’ (BSER). In promulgating 

the implementing regulations, the EPA 

explicitly stated that it is authorized to 

determine the BSER; 86 accordingly, in 

this rulemaking, the EPA is determining 

the BSER. 

The EPA is proposing two alternative 

BSER for fossil fuel-fired EGUs, each of 

which is based on methods that have 

already been employed for reducing 

emissions of air pollutants, including, in 

some cases, CO2, from these sources. 

The first identifies the combination of 

the four building blocks as the BSER. 

These include operational 

improvements and equipment upgrades 

that the coal-fired steam-generating 

EGUs in the state may undertake to 

improve their heat rate (building block 

1) and increases in, or retention of, zeroor low-emitting generation, as well as 

measures to reduce demand for 

generation, all of which, taken together, 

displace, or avoid the need for, 

generation from the affected EGUs 

(building blocks 2, 3, and 4). All of these 

measures are components of a ‘‘system 

of emission reduction’’ for the affected 

EGUs because they either improve the 

carbon intensity of the affected EGUs in 

generating electricity or, because of the 

integrated nature of the electricity 

system and the fungibility of electricity, 

they displace or avoid the need for 

generation from those sources and 

thereby reduce the emissions from those 

sources. Moreover, those measures may 

be undertaken by the affected EGUs 

themselves and, in the case of building 

blocks 2, 3, and 4, they may be required 

by the states. 

Further, these measures meet the 

criteria in CAA section 111(a)(1) and the 

caselaw as the ‘‘best’’ system of 

emission reduction because, among 

other things, they achieve the 

appropriate level of reductions, they are 

of reasonable cost, and they encourage 

technological development that is 

important to achieving further emission 

reductions. Moreover, the measures in 

each of the building blocks are 

‘‘adequately demonstrated’’ because 

they are each well-established in 

numerous states, and many of them 

have already been relied on to reduce 

GHGs and other air pollutants from 

fossil fuel-fired EGUs. It should be 

emphasized that these measures are 

consistent with current trends in the 

electricity sector. 

For the alternative approach for the 

BSER, the EPA is identifying the 

‘‘system of emission reduction’’ as 

including, in addition to building block 

1, the reduction of affected fossil fuelfired EGUs’ mass emissions achievable 

through reductions in generation of 

specified amounts from those EGUs. 

Under this approach, the measures in 

building blocks 2, 3, and 4 would not 

be components of the system of 

emission reduction, but instead would 

serve as bases for quantifying the 

reduction in emissions resulting from 

the reduction in generation at affected 

EGUs. In light of the available sources 

of replacement generation through the 

measures in the building blocks, this 

approach would also meet the criteria 

for being the ‘‘best’’ system that is 

‘‘adequately demonstrated’’ because of 

the emission reductions it would 


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87Public Law 101–549, § 302(a), 104 Stat. at 2574 

(Nov. 15, 1990). 

88Public Law 101–549, § 108(g), 104 Stat. at 2467 

(Nov. 15, 1990). 

achieve, its reasonable cost, and its 

promotion of technological 

development, as well as the fact that the 

reliability of the electricity system 

would be maintained. 

After determining the BSER, the EPA 

is authorized under the implementing 

regulations, as an integral component to 

setting emission guidelines, to apply the 

BSER and determine the resulting 

emission limitation. The EPA is 

proposing to apply the BSER to the 

affected EGUs on a statewide basis. In 

this rulemaking, the EPA terms the 

resulting emission limitation the state 

goal. 

With the promulgation of the 

emission guidelines, each state must 

develop a plan to achieve an emission 

performance level that corresponds to 

the state goal. The state plans must 

establish standards of performance for 

the affected EGUs and include measures 

that implement and enforce those 

standards. Based on requests from 

stakeholders, the EPA is proposing that 

states be authorized to submit state 

plans that do not impose legal 

responsibility on the affected EGUs for 

the entirety of the emission performance 

level, but instead, by adopting what this 

preamble refers to as a ‘‘portfolio 

approach,’’ impose requirements on 

other affected entities (e.g., renewable 

energy and demand-side energy 

efficiency measures) that would reduce 

CO2 emissions from the affected EGUs. 

It should be noted that an important 

aspect of the BSER for affected EGUs is 

that the EPA is proposing to apply it on 

a statewide basis. The statewide 

approach also underlies the required 

emission performance level, which, as 

noted, is based on the application of the 

BSER to a state’s affected EGUs, and 

which the suite of measures in the state 

plan, including the emission standards 

for the affected EGUs, must achieve 

overall. The state has flexibility in 

assigning the emission performance 

obligations to its affected EGUs, in the 

form of standards of performance—and, 

for the portfolio approach, in imposing 

requirements on other entities—as long 

as, again, the required emission 

performance level is met. 

This state-wide approach both 

harnesses the efficiencies of emission 

reduction opportunities in the 

interconnected electricity system and is 

fully consistent with the principles of 

federalism that underlie the Clean Air 

Act generally and CAA section 111(d) 

particularly. That is, this provision 

achieves the emission performance 

requirements through the vehicle of a 

state plan, and provides each state 

significant flexibility to take local 

circumstances and state policy goals 

into account in determining how to 

reduce emissions from its affected 

sources, as long as the plan meets 

minimum federal requirements. This 

state-wide approach, and the standards 

of performance for the affected EGUs 

that the states will establish through the 

state-plan process, are consistent with 

the applicable CAA section 111 

provisions. 

A state has discretion in determining 

the measures in its plans. The state may 

adopt measures that assure the 

achievement of the required emission 

performance level, and is not limited to 

the measures that the EPA identifies as 

part of the BSER. By the same token, the 

affected EGUs, to comply with the 

applicable standards of performance in 

the state plan, may rely on any 

efficacious means of emission 

reduction, regardless of whether the 

EPA identifies those measures as part of 

the BSER. 

In this rulemaking, the EPA proposes 

reasonable deadlines for state plan 

submission and the EPA’s action. The 

proposed deadline for the EPA’s action 

on state plan submittals varies from that 

in the implementing regulations, and 

the EPA is proposing to revise that 

provision in the regulations accordingly. 

Under CAA section 111(d)(2), the state 

plans must be ‘‘satisfactory’’ for the EPA 

to approve them, and in this 

rulemaking, the EPA is proposing the 

criteria that the state plans must meet 

under that requirement. 

The EPA discusses its legal 

interpretation in more detail in other 

parts of this preamble and discusses 

certain issues in more detail in the Legal 

Memorandum included in the docket 

for this rulemaking. The EPA solicits 

comment on all aspects of its legal 

interpretations, including the discussion 

in the Legal Memorandum. 

V. Authority To Regulate Carbon 

Dioxide and EGUs, Affected Sources, 

Treatment of Categories 

A. Authority To Regulate Carbon 

Dioxide 

The EPA has the authority to regulate, 

under CAA section 111(d), CO2

emissions from EGUs, under the 

Agency’s construction of the ambiguous 

provisions in CAA section 

111(d)(1)(A)(i) that identify the air 

pollutants subject to CAA section 

111(d). The ambiguities stem from 

apparent drafting errors that occurred 

during enactment of the 1990 CAA 

Amendments, which revised section 

111(d). 

During the 1990 CAA Amendments, 

the House of Representatives and the 

Senate each passed an amendment to 

CAA section 111(d)(1)(A)(i). The two 

amendments differed from each other, 

and were not reconciled during the 

Conference Committee and, as a result, 

both were enacted into law. As 

amended by the Senate, the pertinent 

language of CAA section 111(d)(1) 

would exclude the regulation of any 

pollutant which is ‘‘included on a list 

published under [CAA section] 

112(b).’’ 87 As amended by the House, 

the pertinent language in CAA section 

111(d)(1) would exclude the regulation 

of any pollutant which is ‘‘emitted from 

a source category which is regulated 

under section 112.’’ 88 The two versions 

conflict with each other and thus are 

ambiguous. Under these circumstances, 

the EPA may reasonably construe the 

provision to authorize the regulation of 

GHGs under CAA section 111(d). 

It should be noted that the U.S. 

Supreme Court’s holding in American 

Electric Power Co. v. Connecticut, 131 S. 

Ct. 2527, 2537–38 (2011), that ‘‘the 

Clean Air Act and the EPA actions it 

authorizes displace any federal common 

law right to seek abatement of carbondioxide emissions from fossil fuel-fired 

power plants’’ was premised on the 

Court’s understanding that CAA section 

111, including CAA section 111(d), 

applies to carbon dioxide emissions 

from those sources. 

We discuss this issue in more detail 

in the Legal Memorandum. 

B. Authority To Regulate EGUs 

Before the EPA finalizes this CAA 

section 111(d) rule, the EPA will 

finalize a CAA section 111(b) 

rulemaking regulating CO2 emissions 

from new EGUs, which will provide the 

requisite predicate for applicability of 

CAA section 111(d). 

CAA section 111(d)(1) requires the 

EPA to promulgate regulations under 

which states must submit state plans 

regulating ‘‘any existing source’’ of 

certain pollutants ‘‘to which a standard 

of performance would apply if such 

existing source were a new source.’’ A 

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

the construction or modification of 

which is commenced after the 

publication of regulations (or, if earlier, 

proposed regulations) prescribing a 

standard of performance under [CAA 

section 111] which will be applicable to 

such source.’’ It should be noted that 

these provisions make clear that a ‘‘new 

source’’ includes one that undertakes 

either new construction or a 

modification. It should also be noted 


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89 In the past, the EPA has issued standards of 

performance under section 111(b) and emission 

guidelines under section 111(d) simultaneously. 

See ‘‘Standards of Performance for new Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills—Final 

Rule,’’ 61 FR 9905 (March 12, 1996). 90See 40 CFR 49.1 to 49.11. 

that the EPA’s implementing regulations 

define ‘‘construction’’ to include 

‘‘reconstruction,’’ which the 

implementing regulations go on to 

define as the replacement of 

components of an existing facility to an 

extent that (i) the fixed capital cost of 

the new components exceeds 50 percent 

of the fixed capital cost that would be 

required to construct a comparable 

entirely new facility, and (ii) it is 

technologically and economically 

feasible to meet the applicable 

standards. 

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

for existing sources to become subject to 

that provision, the EPA must 

promulgate standards of performance 

under CAA section 111(b) to which, if 

the existing sources were new sources, 

they would be subject. Those standards 

of performance may include ones for 

sources that undertake new 

construction, modifications, or 

reconstructions. 

The EPA is in the process of 

promulgating two rulemakings under 

CAA section 111(b) for CO2 emissions 

from affected sources. The EPA 

proposed the first, which applies to 

affected sources undertaking new 

constructions, by notice dated January 

8, 2014, which we refer to as the January 

2014 Proposal. The EPA is proposing 

the second, which applies to affected 

sources undertaking modifications or 

reconstructions, concurrently with this 

CAA section 111(d) proposal. The EPA 

will complete one or both of these CAA 

section 111(b) rulemakings before or 

concurrently with this CAA section 

111(d) rulemaking, which will provide 

the requisite predicate for applicability 

of CAA section 111(d).89

C. Affected Sources 

The EPA is proposing that, for the 

emission guidelines, an affected EGU is 

any fossil fuel-fired EGU that was in 

operation or had commenced 

construction as of January 8, 2014, and 

is therefore an ‘‘existing source’’ for 

purposes of CAA section 111, and that 

in all other respects would meet the 

applicability criteria for coverage under 

the proposed GHG standards for new 

fossil fuel-fired EGUs (79 FR 1430; 

January 8, 2014). 

The January 8, 2014 proposed GHG 

standards for new EGUs generally 

define an affected EGU as any boiler, 

integrated gasification combined cycle 

(IGCC), or combustion turbine (in either 

simple cycle or combined cycle 

configuration) that (1) is capable of 

combusting at least 250 million Btu per 

hour; (2) combusts fossil fuel for more 

than 10 percent of its total annual heat 

input (stationary combustion turbines 

have an additional criteria that they 

combust over 90 percent natural gas); (3) 

sells the greater of 219,000 MWh per 

year and one-third of its potential 

electrical output to a utility distribution 

system; and (4) was not in operation or 

under construction as of January 8, 2014 

(the date the proposed GHG standards of 

performance for new EGUs were 

published in the Federal Register). The 

minimum fossil fuel consumption 

condition applies over any consecutive 

three-year period (or as long as the unit 

has been in operation, if less). The 

minimum electricity sales condition 

applies on an annual basis for boilers 

and IGCC facilities and over rolling 

three-year periods for combustion 

turbines (or as long as the unit has been 

in operation, if less). 

The rationale for this proposal 

concerning applicability is the same as 

that for the January 8, 2014 proposal, 

sections V.A–B. See 79 FR at 1,459/1– 

1,461/2. We incorporate that discussion 

by reference here. 

D. Implications for Tribes and U.S. 

Territories 

As noted in Section II.D of this 

preamble, although affected EGUs 

located in Indian country operate as part 

of the interconnected system of 

electricity production and distribution, 

affected EGUs located in Indian country 

within a state’s borders would not be 

encompassed within the state’s CAA 

section 111(d) plan. The EPA is aware 

of four potentially affected power plants 

located in Indian country: The South 

Point Energy Center, on Fort Mojave 

tribal lands within Arizona; the Navajo 

Generating Station, on Navajo tribal 

lands within Arizona; the Four Corners 

Power Plant, on Navajo tribal lands 

within New Mexico; and the Bonanza 

Power Plant, on Ute tribal lands within 

Utah. The South Point facility is an 

NGCC power plant, and the Navajo, 

Four Corners, and Bonanza facilities are 

coal-fired power plants. The operators 

and co-owners of these four facilities 

include investor-owned utilities, 

cooperative utilities, public power 

agencies, and independent power 

producers, most of which also co-own 

potentially affected EGUs within state 

jurisdictions. We are not aware of any 

potentially affected EGUs that are 

owned or operated by tribal entities. If 

it determines that such a plan is 

necessary or appropriate, the EPA has 

the responsibility to establish CAA 

section 111(d) plans for areas of Indian 

country where affected sources are 

located unless a tribe on whose lands an 

affected source (or sources) is located 

seeks and obtains authority from the 

EPA to establish a plan itself, pursuant 

to the Tribal Authority Rule.90 The EPA 

intends to publish a supplemental 

proposal to establish emission 

performance goals (if it determines that 

such action is necessary or appropriate) 

covering the four potentially affected 

power plants identified above, as well 

as any subsequently identified similarly 

situated power plants, and also to 

proposed goals for U.S. territories with 

affected EGUs. The EPA intends to take 

final action on that proposal by June 

2015. If a tribe does seek and obtain the 

necessary authority to establish a plan 

itself, it is the EPA’s intention that the 

tribe would have flexibility to develop 

a plan tailored to its circumstances, in 

the same manner as a state, to meet CO2

emission performance goals that would 

be established by the EPA based on 

application of the BSER to that area of 

Indian country. The EPA is aware of 

actions that have been taken or are being 

taken by some sources in tribal areas or 

territories and will be mindful of these 

actions in considering establishment of 

a plan. 

The EPA invites comment on whether 

a tribe wishing to develop and 

implement a CAA section 111(d) plan 

should have the option of including the 

EGUs located in its area of Indian 

country in a multi-jurisdictional plan 

with one or more states (i.e., treating the 

tribal lands as an additional state). 

If the EPA develops one or more CAA 

section 111(d) federal plans for areas of 

Indian country with affected EGUs, we 

are likewise currently considering doing 

so on a multi-jurisdictional basis in 

coordination with nearby states 

developing section 111(d) state plans. 

The EPA solicits comment on such an 

approach for a federal plan. 

At this time, the EPA is not proposing 

CO2 emission performance goals for 

areas of Indian country containing 

potentially affected EGUs. We do plan 

to establish such goals in the future, to 

be addressed through either tribal or 

federal plans, as discussed above. The 

EPA notes that some present and 

planned actions being taken to reduce 

criteria pollutants from EGUs in Indian 

country will result in significant CO2

emission reductions relative to 

emissions in the 2012 baseline period 

used in computing the state CO2


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91For example, a plan currently being 

implemented at the Four Corners plant to satisfy 

regional haze requirements calls for reduction of 

NOx emissions to be achieved in part by shutting 

down a portion of the plant’s generating capacity, 

and a similar plan has been proposed for the Navajo 

plant. See 78 FR 62509 (October 22, 2013). 

performance goals in this proposal.91

We invite comment on how the BSER 

should be applied to potentially affected 

EGUs in Indian country. We particularly 

invite comment on data sources for 

setting renewable energy and demandside energy efficiency targets. 

The state-specific goals that the EPA 

is proposing are based on the collection 

of affected EGUs located within that 

state. In setting goals specific to an area 

of Indian country, the EPA proposes to 

base the goals on the collection of 

affected EGUs located within that area 

of Indian country. We request comment 

on this approach. 

E. Combined Categories and 

Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is 

soliciting comment on combining the 

two existing categories for the affected 

EGUs into a single category for purposes 

of facilitating emission trading among 

sources in both categories. The EPA is 

also proposing codifying all of the 

proposed requirements for the affected 

EGUs in a new subpart UUUU of 40 CFR 

part 60. 

As discussed in the January 8, 2014 

proposal for the CAA section 111(b) 

standards for GHG emissions from 

EGUs, in 1971 the EPA listed fossil fuelfired steam generating boilers as a new 

category subject to section 111 

rulemaking, and in 1979 the EPA listed 

fossil fuel-fired combustion turbines as 

a new category subject to the CAA 

section 111 rulemaking. In the ensuing 

years, the EPA has promulgated 

standards of performance for the two 

categories, and codified those standards, 

at various times, in 40 CFR part 60 

subparts D, Da, GG, and KKKK. In the 

2014 proposal, the EPA proposed 

separate standards of performance for 

sources in the two categories and 

proposed codifying the standards in the 

same Da and KKKK subparts that 

currently contain the standards of 

performance for conventional pollutants 

from those sources. In addition, the EPA 

co-proposed combining the two 

categories into a single category solely 

for purposes of the CO2 emissions from 

new construction of affected EGUs, and 

codifying the proposed requirements in 

a new 40 CFR part 60 subpart TTTT. 

The EPA solicited comment on whether 

combining the categories for new 

sources is necessary in order to combine 

the categories for existing sources. 

In the present rulemaking, the EPA is 

proposing emission guidelines for the 

two categories and is soliciting 

comment on combining the two 

categories into a single category for 

purposes of the CO2 emissions from 

existing affected EGUs. The EPA solicits 

comment on whether combining the two 

categories would offer additional 

flexibility, for example, by facilitating 

implementation of CO2 mitigation 

measures, such as shifting generation 

from higher to lower-carbon intensity 

generation among existing sources (e.g., 

shifting from boilers to NGCC units) or 

facilitating emissions trading among 

sources. Because the two categories are 

pre-existing and the EPA would not be 

subjecting any additional sources to 

regulation, the combined category 

would not be considered a new category 

that the EPA must list under CAA 

section 111(b)(1)(A). As a result, this 

proposal does not list a new category 

under section 111(a)(1)(A), nor does this 

proposal revise either of the two source 

categories—steam-generating boilers 

and combustion turbines—that the EPA 

has already listed under that provision. 

Thus, the EPA would not be required to 

make a finding that the combined 

category causes or contributes 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. 

In addition, the EPA is proposing to 

create a new subpart UUUU and to 

include all GHG emission guidelines for 

the affected sources—utility boilers and 

IGCC units as well as natural gas-fired 

stationary combustion turbines—in that 

newly created subpart. We believe that 

combining the emission guidelines for 

affected sources into a new subpart 

UUUU is appropriate because the 

emission guidelines the EPA is 

establishing do not vary by type of 

source. Accordingly, the EPA is not 

proposing to codify any of the 

requirements of this rulemaking in 

subparts Da or KKKK. 

VI. Building Blocks for Setting State 

Goals and the Best System of Emission 

Reduction 

A. Introduction 

Based on the experiences of states and 

the industry and the EPA’s outreach 

with stakeholders as described above, 

the EPA has identified multiple 

measures currently in use for achieving 

CO2 emission reductions from existing 

fossil fuel-fired EGUs. For purposes of 

determining the ‘‘best system of 

emission reduction . . . adequately 

demonstrated’’ (BSER) and developing 

state emission performance goals, we 

have screened the measures and have 

found that they support two alternative 

formulations for the BSER. We are 

grouping the measures that we are 

proposing to consider further at this 

time into four categories, which we call 

‘‘building blocks.’’ We provide an 

overview of these building blocks in 

Section VI.B and more detailed 

discussion of each block in Section 

VI.C. In Section VI.D we discuss 

possible combinations of the building 

blocks, and in Section VI.E, we explain 

why as a legal matter all four building 

blocks, taken together, support the 

BSER, which in turn serves as the basis 

for the standards of performance that 

the states must include in their state 

plans, as CAA section 111(d) requires. 

As discussed in Section III of this 

preamble, we are mindful of numerous 

and varied stakeholder concerns, 

including the need to achieve 

meaningful CO2 emission reductions at 

the affected facilities and to recognize 

and take advantage of the progress 

already made by existing programs. Like 

stakeholders, we are attentive to the 

need to maintain electricity system 

reliability and to minimize adverse 

impacts on electricity and fuel prices 

and on assets that have already been 

improved by installation of controls for 

other kinds of pollution. Many of these 

considerations align with our approach 

to determining the BSER, as discussed 

more in Section VII, and we consider 

several of these to be key principles in 

this application. As discussed in 

Sections VII and VIII, we acknowledge 

and appreciate the advantages of 

allowing and promoting flexibility for 

states in crafting their programs. We 

recognize the knowledge that states 

have about their specific situations and 

their ability to evaluate and leverage 

existing and new capacity and programs 

to ultimately reduce EGU CO2

emissions. 

Similarly, we recognize and 

appreciate that states operate with 

differing circumstances and policy 

preferences. For example, states have 

differing access to specific fuel types, 

and the variety of types of EGUs 

operating in different states is broad and 

significant. States are part of assorted 

EGU dispatch systems and vary in the 

amounts of electricity that they import 

and export. For these reasons, we also 

recognize and appreciate the value in 

allowing and promoting multi-state 

reduction strategies. Some states already 

participate in a multi-state program that 

reduces CO2 emissions, the RGGI, and 

we have noted the success of that 

program for those states. 


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92The EPA is aware of the potential that one or 

more facilities involved in programs mentioned or 

relied on in this proposal may have received some 

form of assistance under the Energy Policy Act of 

2005 (EPAct). Section 402 (i) of the EPAct (codified 

at 42 U.S.C. section 15962(i)) states: 

‘‘No technology, or level of emission reduction, 

solely by reason of the use of the technology, or the 

achievement of the emission reduction, by 1 or 

more facilities receiving assistance under this Act, 

shall be considered to be—(1) adequately 

demonstrated for purposes of section 111 of the 

Clean Air Act (42 U.S.C. 7411)[.]’’ 

In a February 26, 2014 Notice of Data 

Availability, the EPA proposed to give this 

provision its natural meaning: the term ‘‘solely’’ 

modifies all of the provisions, so that any 

‘‘adequately demonstrated’’ finding by the EPA 

could not be based solely upon technology, level of 

emission reduction, or achievement of the emission 

reduction by a facility (or facilities) receiving 

assistance. The EPA proposes the same 

interpretation here. The EPA further believes that 

its proposed determination of the ‘‘best system of 

emission reduction . . . adequately demonstrated’’ 

does not depend exclusively on technology, level of 

emission reduction, or achievement of emission 

reduction from facilities receiving EPAct assistance, 

given the myriad number of technologies and 

emission performance on which that proposed 

determination is based. 

93Elsewhere in the preamble we refer to the 

potential for efficiency improvements to lead to 

increased competitiveness and therefore increased 

utilization as a ‘‘rebound effect.’’ 

94For simplicity, throughout this preamble we 

generally refer to the energy output produced by 

EGUs as electricity, recognizing that some EGUs 

produce a portion of their energy output in other 

forms, such as steam for heating or process uses. 

The discussion here applies to both EGUs that 

produce only electricity and EGUs that produce a 

combination of electricity and other energy output. 

95The EPA assessed opportunities to achieve CO2

reductions through heat rate improvements at both 

coal-fired steam EGUs and non-coal-fired fossil 

fuel-fired EGUs, such as oil/gas-fired steam EGUs 

and NGCC units. At this time we are proposing that 

the basis for supporting the BSER should include 

heat rate improvements only at coal-fired steam 

EGUs, but we are inviting comment on including 

heat rate improvements at other EGU types. See 

Section VI.C.5 for further discussion of our 

assessment of heat rate opportunities for non-coalfired EGUs. 

96These estimated ranges are averages applicable 

to the fleet of coal-fired steam EGUs as a whole. 

Potential improvements at individual EGUs could 

be higher or lower. 

97As noted above, in the absence of other kinds 

of CO2 emission reduction measures, the emission 

reductions achievable through heat rate 

improvements could be offset to some extent by 

increased utilization of EGUs making the 

improvements (a ‘‘rebound effect’’). See Section 

VI.C.1 below for further discussion. 

Another key consideration in 

determining the BSER, as discussed 

more in the following sections, is the 

relationship between the timing of 

measures and their effectiveness in 

limiting emissions. For example, actions 

that can occur in the near term, such as 

improvements to individual EGU heat 

rates, may fail to achieve the cumulative 

emission reductions that sustained 

implementation of other actions, such as 

demand-side energy efficiency 

programs, may achieve over time. 

B. Building Blocks for the Best System 

of Emission Reduction 

This subsection summarizes the 

EPA’s analytic approach to determining 

the best system of emission reduction 

(BSER) for CO2 emissions from existing 

EGUs. Later subsections discuss 

particular measures and how they form 

the basis of the BSER.92

1. Overview of Approach 

In considering the appropriate scope 

of the proposed BSER, the EPA 

evaluated three basic groupings of 

strategies for reducing CO2 emission 

from EGUs: (i) Reductions achievable 

through improvements in individual 

EGUs’ emission rates (referred to 

throughout this preamble as ‘‘building 

block 1’’); (ii) EGU CO2 emissions 

reductions achievable through redispatch from affected steam EGUs to 

affected NGCC units (‘‘building block 

2’’); and (iii) EGU CO2 emissions 

reductions achievable by meeting 

demand for electricity or electricity 

services through expanded use of lowor zero-carbon generating capacity 

(‘‘building block 3’’) and through 

expanded use of demand-side energy 

efficiency (‘‘building block 4’’). While 

the first grouping plays the same role in 

each of our two formulations of the 

BSER, the second and third groupings 

play different roles: In the first 

formulation they constitute components 

of the BSER, and in the second 

formulation they serve as the basis for 

why a component of that formulation of 

the BSER—reduced utilization of the 

higher-emitting affected EGUs—is 

adequately demonstrated. 

As described in the remainder of this 

section, the EPA concluded that while 

certain strategies within the first 

grouping clearly should be part of the 

BSER, it was not appropriate to limit 

consideration of the BSER to this first 

grouping, for several reasons. First, we 

determined that some strategies 

available in the other two groupings can 

support reduced CO2 emissions from the 

fossil fuel-fired EGUs by significant 

amounts and at lower costs than some 

of the strategies in the first grouping. 

Second, we observed that strategies in 

all three groupings were already being 

pursued by states and sources taking 

advantage of the integrated nature of the 

electricity system, at least in part for the 

purpose of reducing CO2 emissions. 

Third, we were concerned that if 

measures from the first grouping that 

improve heat rates at coal-fired steam 

EGUs were implemented in isolation, 

without additional measures that 

encourage substitution of less carbonintensive ways of providing electricity 

services for more carbon-intensive 

generation, the resulting increased 

efficiency of coal-fired steam units 

would provide incentives to operate 

those EGUs more, leading to smaller 

overall reductions in CO2 emissions.93

These factors reinforced the 

appropriateness of our considering 

strategies from all three groupings for 

purposes of determining the BSER. 

2. CO2 Reductions Achievable Through 

Improvements in Individual EGUs’ 

Emission Rates 

The first grouping of CO2 emission 

reduction options that the EPA 

evaluated as potential options for the 

BSER consists of measures that can 

reduce individual EGUs’ CO2 emission 

rates (i.e., the amount of CO2 emitted 

per unit of electricity 94 output). These 

measures included improving the 

efficiency with which EGUs convert fuel 

heat input to electricity output (i.e., heat 

rate improvements), applying carbon 

capture and storage (CCS) technology, 

and substituting lower-carbon fuels 

such as natural gas for higher-carbon 

fuels such as coal (i.e., natural gas cofiring or conversion). 

Our assessment of heat rate 

improvements showed that these 

measures would achieve CO2 emission 

reductions at low costs, although 

compared to other measures, the 

available reductions were relatively 

limited in quantity.95 Specifically, our 

analysis indicated that average CO2

emission reductions of 1.3 to 6.7 percent 

could be achieved by coal-fired steam 

EGUs through adoption of best 

practices, and that additional average 

reductions of up to four percent could 

be achieved through equipment 

upgrades.96 Heat rate improvements pay 

for themselves at least in part through 

reductions in fuel costs, generally 

making this a relatively inexpensive 

approach for reducing CO2 emissions. 

We estimated that CO2 reductions of 

between four and six percent from 

overall heat rate improvements could be 

achieved on average across the nation’s 

fleet of coal-fired steam EGUs for net 

costs in a range of $6 to $12 per metric 

ton.97

The EPA also examined application of 

CCS technology at existing EGUs. CCS 

offers the technical potential for CO2

emission reductions of over 90 percent, 

or smaller percentages in partial 

applications. In the recently proposed 

Carbon Pollution Standards for new 

fossil fuel-fired EGUs (79 FR 1430), we 

found that partial CCS was adequately 

demonstrated for new fossil fuel-fired 

steam EGUs and integrated gasification 


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98CCS already has been or is being implemented 

at some existing EGUs, as noted in the discussion 

of CCS later in the preamble. 

99As noted later in this preamble, we are 

nevertheless seeking comment on the extent to 

which existing EGUs could implement CCS in order 

to improve our understanding. 

100The lower end of the range is for conversion 

to 100 percent natural gas, which would allow 

EGUs to eliminate certain fixed operating and 

maintenance costs associated with coal use but not 

natural gas use. See Section VI.C.5.a below for 

further discussion. 

101Strategies in this grouping also include 

shifting generation from steam EGUs burning oil or 

natural gas to more efficient NGCC units. 

102This estimate assumes an average heat rate of 

10,434 Btu/kWh for coal fossil fuel-fired steam 

units between 400 and 600 MW and 7,130 Btu/kWh 

for NGCC units between 400 and 600 MW. See 

NEEDSv.5.13 at http://www.epa.gov/

powersectormodeling/BaseCasev513.html. 

103See Section VI.C.2 below for further 

discussion. 

104EIA Form 860, available at http://www.eia.gov/ 

electricity/data/eia860. In comparison, in 2012 

there was 336 GW of coal steam capacity, of which 

22 GW was placed in service between 2000 and 

2012. Id. 

combined cycle (IGCC) units. We also 

found that for these new units the costs 

were not unreasonable, either for 

individual units or on a national basis, 

and we proposed to find that 

application of partial CCS is the BSER. 

However, application of CCS at existing 

units would entail additional 

considerations beyond those at issue for 

new units. Specifically, the cost of 

integrating a retrofit CCS system into an 

existing facility would be expected to be 

substantial, and some existing EGUs 

might have space limitations and thus 

might not be able to accommodate the 

expansion needed to install CCS. 

Further, the aggregated costs of applying 

CCS as a component of the BSER for the 

large number of existing fossil fuel-fired 

steam EGUs would be substantial and 

would be expected to affect the cost and 

potentially the supply of electricity on 

a national basis. For these reasons, 

although some individual facilities may 

find implementation of CCS to be a 

viable CO2 mitigation option in their 

particular circumstances,98 the EPA is 

not proposing and does not expect to 

finalize CCS as a component of the 

BSER for existing EGUs in this 

rulemaking.99 Nevertheless, CCS would 

be available to states and sources as a 

compliance option. 

Natural gas co-firing or conversion at 

coal-fired steam EGUs offers greater 

potential CO2 emission reductions than 

heat rate improvements, but at a higher 

cost (although less than the cost of 

applying CCS technology). Because 

natural gas contains less carbon than an 

energy-equivalent quantity of coal, 

converting a coal-fired steam EGU to 

burn only natural gas would reduce the 

unit’s CO2 emissions by approximately 

40 percent. The CO2 reductions are 

generally proportional to the amount of 

gas substituted for coal, so if an EGU 

continued to burn mostly coal while cofiring natural gas as, for example, 10 

percent of the EGU’s total heat input, 

the CO2 emission reductions would be 

approximately four percent. The EPA 

determined that the most significant 

cost associated with natural gas 

conversion or co-firing is likely to be the 

incremental cost of natural gas relative 

to the cost of coal. Using Energy 

Information Administration (EIA) fuel 

price projections, we estimated that the 

CO2 reductions achieved through 

natural gas conversion or co-firing at an 

average coal-fired steam EGU would 

have costs ranging from approximately 

$83 to $150 per metric ton.100 Thus, 

although there have been past instances 

where coal-fired steam EGUs have been 

converted to natural gas, and we expect 

some additional future conversions 

where circumstances at individual 

EGUs make the option particularly 

attractive, for the industry as a whole 

we would expect that other approaches 

could reduce CO2 emissions from 

existing EGUs at lower cost. However, 

gas conversion or co-firing would be 

available to states and sources as a 

compliance option, and, as noted later 

in the preamble, we are seeking 

comment on whether this option should 

be considered part of the BSER. 

3. CO2 Emission Reductions Achievable 

Through Re-Dispatch From Steam EGUs 

to NGCC Units 

The second grouping of CO2 emission 

reduction options evaluated by the EPA 

in the BSER analysis involves reducing 

emissions by shifting generation among 

affected EGUs. An obvious alternative to 

substituting natural gas for coal at 

individual steam EGUs through 

conversion or co-firing is instead to use 

natural gas to generate electricity at a 

different affected EGU with a better heat 

rate—notably a natural gas combined 

cycle (NGCC) unit—and to substitute 

that electricity for electricity from the 

coal-fired steam EGU, thus resulting in 

lower emissions from the coal-fired 

steam EGU and lower emissions from 

the set of affected EGUs overall.101 The 

electricity system is physically 

interconnected or networked and 

operated on an integrated basis across 

large regions. System operators 

routinely increase or decrease the 

electricity output of individual EGUs to 

respond to changes in electricity 

demand, equipment availability, and 

relative operating costs (or bid prices) of 

individual EGUs while observing 

reliability-related constraints. It has long 

been common industry practice for 

system operators to choose from among 

multiple EGUs when deciding which 

EGU to ‘‘dispatch’’ to generate the next 

increment of electricity needed to meet 

demand. Thus, the well-established 

practices of the industry support our 

evaluation of ‘‘re-dispatch’’ of 

generation from steam EGUs to NGCC 

units as a potential component of the 

basis for the BSER to reduce CO2

emissions from existing EGUs. 

NGCC units can produce as much as 

46 percent more electricity from a given 

quantity of natural gas than steam 

EGUs,102 making the re-dispatch 

approach a significantly less expensive 

way to reduce CO2 emissions than 

conversion or co-firing of coal-fired 

steam EGUs to burn natural gas. For 

example, using the same EIA fuel cost 

projections as were used above to 

estimate the costs of natural gas 

conversion or co-firing, we estimated 

that the cost of CO2 reductions 

achievable by substituting electricity 

from an existing NGCC unit for 

electricity from an average coal-fired 

steam EGU would be approximately $30 

per metric ton.103

Our analysis indicated that the 

potential CO2 reductions available 

through re-dispatch from steam EGUs to 

NGCC units are substantial. As of 2012, 

there was approximately 245 GW of 

NGCC capacity in the United States, 196 

GW of which was placed in service 

between 2000 and 2012.104 In 2012, the 

average utilization rate of U.S. NGCC 

capacity was 46 percent, well below the 

utilization rates the units are capable of 

achieving. In 2012 approximately 10 

percent of NGCC plants operated at 

annual utilization rates of 70 percent or 

higher, and 19 percent of NGCC units 

operated at utilization rates of at least 70 

percent over the summer season. 

Average reported availability generally 

exceeds 85 percent. We recognize that 

the ability to increase NGCC utilization 

rates may also be affected by 

infrastructure and system 

considerations, such as limits on the 

ability of the natural gas industry to 

produce and deliver the increased 

quantities of natural gas, the ability of 

steam EGUs to reduce generation while 

remaining ready to supply electricity 

when needed in peak demand hours, 

and the ability of the electric 

transmission system to accommodate 

the changed geographic pattern of 

generation. However, these 

considerations have not limited past 

rapid increases in NGCC generation 

levels, as indicated by a 20 percent 

increase in natural gas consumption for 


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105EIA Form 923, available at http://www.eia.gov/ 

electricity/data/eia923/. 

106Substitution would only occur to the extent 

that there is both NGCC capacity whose generation 

could be increased and steam EGUs whose 

generation could be decreased. 

107See Section VI.C.3 below for further 

discussion. 

108See Section VI.C.4 below for further 

discussion. 

electricity generation from 2011 to 

2012.105 Further, we have taken these 

considerations into account, and the 

proposal’s compliance schedule 

provides flexibility and time for 

investment in additional natural gas and 

electric industry infrastructure if 

needed. 

As discussed below in Section VI.C.2, 

the data and considerations cited above 

support our assessment that an average 

NGCC utilization rate in a range of 65 

to 75 percent is a reasonable target for 

the amount of additional NGCC 

generation that could be substituted for 

higher carbon generation from steam 

EGUs as part of the BSER.106 If redispatch consistent with a target average 

NGCC utilization rate of 70 percent had 

been achieved in 2012, the combined 

CO2 emissions of steam EGUs and 

NGCCs would have been reduced by 

approximately 13 percent. 

Finally, we also note that mechanisms 

for encouraging re-dispatch as a CO2

reduction measure have already been 

developed and applied in the industry. 

Under both RGGI and California’s 

Global Warming Solutions Act, shifting 

generation from more carbon-intensive 

EGUs to less carbon-intensive EGUs is a 

way to facilitate compliance with 

regulatory requirements. In both cases, 

the industry has demonstrated the 

ability to respond to the regulatory 

requirements of these state programs. 

4. CO2 Emission Reductions Achievable 

Through Other Actions Underway in the 

Industry 

The third grouping of CO2 emission 

reduction options the EPA evaluated in 

the BSER analysis encompasses other 

measures already used in the industry 

and not included in the first two 

groupings. From our evaluation of redispatch as an option for reducing CO2

emissions, it was apparent that relevant 

factors for consideration include the 

integrated nature of the electricity 

system and the fact that particular 

measures capable of reducing CO2

emissions at EGUs were already being 

used and would continue to be used 

throughout the industry, either for the 

purpose of compliance with CO2

emission reduction requirements or to 

serve other purposes and policy goals. 

That observation led us to consider 

what other potential actions and options 

the industry was already using that had 

resulted in or could result in, or 

support, the reduction of CO2 emissions 

at EGUs. Again, we observed many such 

instances, some taking place incidental 

to the routine operation of the electricity 

system and others taking place in 

response to specific state initiatives to 

reduce CO2 emissions from the power 

sector. We concluded that there are two 

principal types of such potential options 

for measures that support CO2 emission 

reductions at EGUs affected under this 

proposal: Ongoing development and use 

of low- and zero-carbon generating 

capacity, and ongoing development and 

application of demand-side energy 

efficiency measures. 

Low-and zero-carbon generating 

capacity provides electricity that can be 

substituted for generation from more 

carbon-intensive EGUs. More than half 

the states already have established some 

form of state-level renewable energy 

requirements, with targets calling on 

average for almost 20 percent of 2020 

generation to be supplied from 

renewable sources. The EPA is unaware 

of analogous state policies to support 

development of new nuclear units, but 

30 states already have nuclear EGUs 

(with five units under construction) and 

the generation from these units is 

currently helping to avoid CO2

emissions from fossil fuel-fired EGUs. 

Policies that encourage development of 

renewable energy capacity and 

discourage premature retirement of 

nuclear capacity could be useful 

elements of CO2 reduction strategies and 

are consistent with current industry 

behavior. Costs of CO2 reductions 

achievable through these policies have 

been estimated in a range from $10 to 

$40 per metric ton.107

Demand-side energy efficiency 

programs produce electricity-dependent 

services with less electricity, and 

thereby support reduced generation 

from existing fossil fuel-fired EGUs by 

reducing the demand for that 

generation. Reduced generation results 

in lower CO2 emissions. More than 40 

states already have established some 

form of demand-side energy efficiency 

polices, and individual states have 

avoided up to 13 percent of their 

electricity demand. Again, policies that 

encourage demand-side energy 

efficiency could be useful elements of 

CO2 reduction strategies and are 

consistent with current industry 

behavior. Using conservatively high 

estimates of the costs of demand-side 

energy efficiency, the EPA estimates 

that the costs of CO2 emission 

reductions achievable consistent with 

such policies would be in a range of $16 

to $24 per metric ton.108

5. Summary of Building Blocks for the 

Best System of Emission Reduction 

Based on the analytic approach 

summarized above, the EPA has 

identified the following four principal 

categories—‘‘building blocks’’—of 

measures that provide the foundation of 

our BSER determination for CO2

emissions from existing EGUs: 

1. Reducing the carbon intensity of 

generation at individual affected EGUs 

through heat rate improvements. 

2. Reducing emissions from the most 

carbon-intensive affected EGUs in the 

amount that results from substituting 

generation at those EGUs with 

generation from less carbon-intensive 

affected EGUs (including NGCC units 

under construction). 

3. Reducing emissions from affected 

EGUs in the amount that results from 

substituting generation at those EGUs 

with expanded low- or zero-carbon 

generation. 

4. Reducing emissions from affected 

EGUs in the amount that results from 

the use of demand-side energy 

efficiency that reduces the amount of 

generation required. 

Since they either result in improved 

operating efficiency or support 

reductions in mass emissions at existing 

EGUs, each of the four building blocks 

represents a demonstrated basis for 

reducing CO2 emissions from affected 

EGUs that is already being pursued in 

the power sector. In the next subsection, 

we discuss each of the building blocks 

at length. Our approach for applying the 

building blocks to each state’s 

circumstances in order to develop state 

goals is described in Section VII of this 

preamble. 

C. Detailed Discussion of Building 

Blocks and Other Options Considered 

In this subsection we discuss each of 

the building blocks in turn. For each 

building block, we provide our 

proposed assessment of the technical 

potential of the building block and the 

reasonableness of its costs within the 

context of the BSER determination, and 

we describe how we developed the data 

inputs used in the computations of the 

proposed state goals described in 

Section VII.C and the alternate goals 

offered for comment in Section VII.E. 

We also discuss certain measures that 

we are not proposing to consider as part 

of the best system of emission 

reduction. Additional detail is provided 


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109A ‘‘steam EGU’’ is an EGU that combusts fuel 

in a boiler and uses the combustion heat to create 

steam which is then used to drive a steam turbine 

that drives a generator to create electricity. In 

contrast, a ‘‘combined cycle EGU’’ combusts fuel in 

a combustion turbine that directly drives a 

generator, and the waste heat is then used to create 

steam which is used to drive a steam turbine that 

drives a generator to create more electricity. Steam 

EGUs can combust a wide variety of fuels including 

coal and natural gas. Combined cycle EGUs are 

more efficient at converting fuel energy to electric 

energy but are limited to gaseous or liquid fuels, 

most commonly natural gas or distillate oil. Almost 

all existing coal-fired EGUs are steam EGUs (the 

exceptions are integrated gasification combined 

cycle (IGCC) units where coal is processed to create 

a gaseous fuel that is then combusted in a combined 

cycle unit). 

110As noted in Section VI.C.5.d below, we are 

taking comment on including heat rate 

improvement opportunities at other EGU types in 

the basis for supporting the BSER. Also, for 

compliance purposes states and EGUs would be 

able to rely on CO2 emission reductions achieved 

through heat rate improvements at other types of 

EGUs. 

111Heat rate can also be expressed on a gross 

basis—i.e., fuel input per kWh of gross electricity 

generated—instead of a net basis—i.e., fuel input 

per kWh of net electricity sent to the grid. The 

difference between gross and net electricity is the 

amount of electricity used at the plant to operate 

components such as pumps, fans, motors, and 

pollution control devices. 

112See NEEDSv.5.13 at http://www.epa.gov/

powersectormodeling/BaseCasev513.html. 

113A small portion of some fossil fuel-fired EGU’s 

CO2 emissions may come from sources other than 

fuel, such as limestone or other carbonates used to 

capture sulfur dioxide (SO2) and/or hydrogen 

chloride (HCl) in a scrubber or dry injection system. 

However, CO2 emissions from these reagents will 

also tend to be reduced by heat rate improvements, 

because reagent usage, and the associated CO2

emissions, will decrease when the amount of fuel 

used decreases. 

114See chapter 2 of the GHG Abatement Measures 

TSD for details. 

in the Greenhouse Gas Abatement 

Measures TSD. 

It is worth noting that although the 

discussion below necessarily addresses 

the building blocks individually, states 

are not required to pursue plans 

involving any given building block or to 

do so at any particular level of 

stringency. Rather, states have flexibility 

to establish plans to meet their state 

emission limitations using their own 

preferred combinations of efficacious 

measures applied to the extent 

determined appropriate by the states. 

The EPA expects that states and affected 

EGUs are unlikely to limit themselves to 

the measures in any single building 

block, but instead are likely to pursue 

portfolios of measures from a 

combination of the actions encompassed 

in the building blocks. In developing the 

data inputs to be used in computing 

state goals, the EPA has estimated 

reasonable rather than maximum 

possible implementation levels for each 

building block in order to establish 

overall state goals that are achievable 

while allowing states to take advantage 

of the flexibility to pursue some 

building blocks more extensively, and 

others less extensively, than is reflected 

in the goal computations, according to 

each state’s needs and preferences. 

1. Building Block 1—Heat Rate 

Improvements 

The first category of approaches to 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs consists of 

measures that reduce the carbon 

intensity of generation at individual 

coal-fired steam EGUs 109 by improving 

heat rate. Heat rate improvements are 

changes that increase the efficiency with 

which an EGU converts fuel energy to 

electric energy (and useful thermal 

energy in the case of units that 

cogenerate steam for process use as well 

as electricity), thereby reducing the 

amount of fuel needed to produce the 

same amount of electricity and lowering 

the amount of CO2 produced as a 

byproduct of fuel combustion. Heat rate 

improvements yield important benefits 

to affected sources by reducing their 

fuel costs. 

The EPA is aware of the potential for 

‘‘rebound effects’’ from improvements 

in heat rates at individual EGUs. In this 

context, a rebound effect would occur 

where, because of an improvement in its 

heat rate, an EGU experiences a 

reduction in variable operating costs 

that makes the EGU more competitive 

relative to other EGUs and consequently 

raises the EGU’s generation output. The 

increase in the EGU’s CO2 emissions 

associated with the increase in 

generation output would offset the 

reduction in the EGU’s CO2 emissions 

caused by the decrease in its heat rate 

and rate of CO2 emissions per unit of 

generation output. The extent of the 

offset would depend on the extent to 

which the EGU’s generation output 

increased (as well as the CO2 emission 

rates of the EGUs whose generation was 

displaced). The EPA considers the 

rebound effect to be a potential concern 

if heat rate improvements were the only 

approaches being considered for the 

BSER, but believes that the effect can be 

addressed by establishing the BSER as a 

combination of approaches that 

includes not only heat rate 

improvements but also approaches that 

will encourage reductions in electricity 

demand or increases in generation from 

lower- or zero-emitting EGUs. The topic 

of potential rebound effects is discussed 

further in Sections VI.D and VI.E below. 

For purposes of the remainder of this 

subsection, no rebound effect is 

assumed. 

Although heat rate improvements 

have the potential to reduce CO2

emissions from all types of affected 

EGUs, the EPA’s analysis indicates the 

potential is significantly greater for coalfired steam EGUs than for other EGUs, 

and for purposes of determining the best 

system of emission reduction at this 

time, the EPA is conservatively 

proposing to base its estimate of CO2

emission reductions from heat rate 

improvements on coal-fired steam EGUs 

only.110 The remainder of this 

subsection focuses on the EPA’s 

analysis of potential heat rate 

improvements from coal-fired steam 

EGUs. Our analysis of potential heat rate 

improvements from other types of 

affected EGUs is addressed in Section 

VI.C.5 below. 

a. Ability of Heat Rate Improvements To 

Reduce CO2 Emissions 

The heat rate of an EGU is the amount 

of fuel energy input needed (Btu, higher 

heating value basis) to produce 1 kWh 

of net electrical energy output (and 

useful thermal energy in the case of 

cogeneration units).111 The current 

weighted-average annual heat rate of 

U.S. coal-fired EGUs in the range of 400 

to 600 MW is approximately 10,434 Btu 

per net kWh.112 Because an EGU’s CO2

emissions are driven primarily by the 

amount of fuel consumed, at any fossil 

fuel-fired EGU there is a strong 

correlation between potential heat rate 

improvements and potential reductions 

in carbon-intensity.113

Several studies have examined the 

opportunities to employ heat rate 

improvements as a means of reducing 

CO2 emissions from coal-fired power 

plants.114 Among these, a 2009 study by 

the engineering firm Sargent & Lundy 

used bottom-up engineering approaches 

evaluating potential heat rate 

improvements from specific best 

practices and equipment upgrades, 

including upgrades to boilers, steam 

turbines, and control systems. Based on 

this study, the EPA believes that 

implementation of all identified best 

practices and equipment upgrades at a 

facility could provide total heat rate 

improvements in a range of 

approximately 4 to 12 percent. (We 

recognize that individual EGUs would 

only be able to implement the best 

practices or upgrades that were 

applicable to their specific designs or 

fuel types and that had not already been 

implemented.) 

In addition to the Sargent & Lundy 

study, which looked generically at the 

types of improvements that can be made 

at specific types of EGUs, historical heat 

rate data also provides a basis for 


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115Temperature data are from the National 

Oceanic and Atmospheric Administration’s 

Integrated Surface Data, http://www.ncdc.noaa.gov/ 

data-access/land-based-station-data/land-baseddatasets/integrated-surface-database-isd. Electrical 

generation data are from the EPA’s Air Markets 

Program Data, http://ampd.epa.gov/ampd/. 116We examined whether the potential for heat 

rate improvement varied based on EGU 

characteristics such as capacity, boiler type, and 

location, and found no meaningful differences. 

117Electric Power Research Institute 2011 

Technical Report—Program on Technology 

Innovation: Electricity Use in the Electric Sector 

discerning the existence and possible 

magnitude of potential heat rate 

improvements. Many EGUs regularly 

report to both the EPA and the U.S. 

Department of Energy’s Energy 

Information Administration (EIA) CO2

emissions and generation data, from 

which heat input and heat rate data can 

be computed. We have reviewed these 

data and have identified several ‘‘data 

apparent’’ instances where an EGU’s 

heat rate experienced a substantial 

improvement in a short time— 

presumably because of equipment 

upgrades installed at that point in 

time—that was then sustained. These 

heat rate improvements ranged from 3 to 

8 percent. In combination with bottomup engineering analysis and the further, 

more detailed EPA analysis of hourly 

data summarized below, the individual 

EGU heat rate histories provide a strong 

basis for considering heat rate 

improvement as a meaningful potential 

approach to reducing the carbon 

intensity of generation at individual 

affected fossil fuel-fired EGUs. 

b. Amounts of Heat Rate Improvements 

In order to estimate the technical 

potential of heat rate improvement 

opportunities at existing fossil fuel-fired 

EGUs suggested by the discussion 

above, the EPA pursued two principal 

areas of analysis. The first area 

concerned the heat rate improvements 

that could be achieved by reducing heat 

rate variability at individual coal-fired 

EGUs through adoption of best practices 

for operation and maintenance. The 

second area concerned heat rate 

improvement opportunities that could 

be achieved through further equipment 

upgrades. Both analyses are summarized 

below along with our conclusions, and 

are discussed in greater detail in the 

GHG Abatement Measures TSD. 

For the best practices analysis, the 

EPA worked with the hourly data 

reported to the EPA by affected EGUs 

subject to the monitoring and reporting 

requirements of 40 CFR Part 75. The 

reported data include hourly heat input 

and, for most reporting EGUs, hourly 

gross generation, making it possible to 

compute hourly gross heat rates. We 

used the hourly data to assess variability 

in the hourly gross heat rates of 

approximately 900 individual coal-fired 

steam EGUs over the period from 2002 

to 2012. Specifically, the EPA evaluated 

the consistency with which individual 

EGUs maintained their hourly heat rates 

over time. We expected that a certain 

degree of short-term heat rate variability 

was caused by factors beyond operators’ 

control, notably variation in hourly 

ambient temperature and hourly load, 

and preliminary analysis confirmed our 

expectation. We therefore controlled for 

variation in those factors by grouping 

the observed hourly heat rate data for 

each EGU into subsets corresponding to 

ranges of hourly ambient temperatures 

and hourly load levels.115 We believe 

that the amount of residual variability 

within each data subset is an indication 

of the degree of technical potential to 

improve the consistency with which 

optimal heat rate performance is 

achieved by adopting operating and 

maintenance best practices. For 

example, optimal heat rate performance 

could be achieved with greater 

consistency through practices such as 

turning off unneeded pumps at reduced 

loads, installation of digital control 

systems, more frequent tuning of 

existing control systems, or earlier likekind replacement of worn existing 

components. (Upgrades to existing 

equipment are considered below.) By 

applying best practices to their 

operating and maintenance procedures, 

owners and operators of EGUs could 

reduce heat rate variability relative to 

average heat rates and, because the 

deviations generally result in 

performance worse than the optimal 

heat rates, improve the EGUs’ average 

heat rates. Assuming that between 10 

percent and 50 percent of the deviation 

from top decile performance in each 

subset of hourly heat rate observations 

within defined ranges of temperature 

and load could be eliminated through 

adoption of best practices, the result is 

a corresponding estimated range of 1.3 

percent to 6.7 percent technical 

potential for improvement in the 

average heat rate of the entire fleet of 

coal-fired EGUs.116 Based on this 

analysis, we believe a reasonable 

estimate for purposes of developing 

state-specific goals is that affected coalfired steam EGUs on average could 

achieve a four percent improvement in 

heat rate through adoption of best 

practices to reduce hourly heat rate 

variability. This estimate corresponds to 

the elimination, on average across the 

fleet of affected EGUs, of 30 percent of 

the deviation from top-decile 

performance in the hourly heat rate for 

each EGU not attributable to hourly 

temperature and load variation. We also 

solicit comment on the use of estimates 

up to six percent, reflecting elimination 

on average of 50 percent of the deviation 

from top-decile performance. 

For the equipment upgrade analysis, 

we evaluated potential opportunities to 

improve heat rates at affected EGUs 

through specific upgrades identified in 

the 2009 Sargent & Lundy study. In that 

study, Sargent & Lundy estimated 

ranges of potential heat rate 

improvement achievable through a 

variety of equipment upgrades. We 

screened the upgrades from the study to 

identify what we consider to be a 

reasonable subset of equipment 

upgrades that would generally be 

beyond the scope of investments we 

would expect to be made for purposes 

of achieving the best-practices heat rate 

improvements discussed above. Based 

on the average of the study’s ranges of 

potential heat rate improvements from 

the various upgrades in this subset, 

implementation of the full subset of 

appropriate opportunities at a single 

EGU could be expected to result in an 

aggregate heat rate improvement of 

approximately four percent (incremental 

to the improvement achievable from 

adoption of best practices). However, we 

recognize that this total may overstate 

the average equipment upgrade 

opportunity across all EGUs because 

some EGUs may have already 

implemented some of these upgrades. 

We therefore propose to use as a data 

input for purposes of developing state 

goals an estimate that, on average across 

the fleet of affected EGUs, only half of 

the full equipment upgrade opportunity 

just described remains—i.e., that for the 

fleet of affected EGUs as a whole, the 

technical potential for heat rate 

improvements from equipment 

upgrades incremental to the bestpractices opportunity is on average two 

percent rather than four percent. We 

solicit comment on increasing this 

figure up to four percent. 

Some of the measures available to 

EGUs for reducing their carbon intensity 

affect net heat rates rather than gross 

heat rates. Various EGU components 

such as pumps, fans, motors, and 

pollution control devices use electricity, 

a factor that is not accounted for in gross 

heat rates (that is, fuel used per unit of 

gross energy output) but is accounted 

for in net heat rates (that is, fuel used 

per unit of net energy output sent to the 

electric grid or used for thermal 

purposes). The electricity used by these 

components, referred to as auxiliary or 

parasitic load, may represent from 4 to 

12 percent of gross generation at a coalfired steam EGU.117 The analysis of 


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(Opportunities to Enhance Electric Energy 

Efficiency in the Production and Delivery of 

Electricity). 

118As proposed, the state-specific goals are 

expressed in the form of CO2 emissions per net 

MWh, and reporting requirements for sources 

would be in the same form, allowing parasitic load 

reductions to contribute to improved measured heat 

rates. If goals and reporting requirements were 

changed to a gross MWh basis in the final rule, 

accounting for parasitic load reductions as a source 

of CO2 reductions would require additional 

procedures. 

119 10,450 Btu/kWh * 8760 hours/year * 78% 

utilization * $2.62 per MMBtu * 6% improvement 

* 0.000001 MMBtu/Btu = $11.2 per kW-year. Data 

inputs for average coal-fired EGU heat rate, average 

coal-fired EGU utilization, and average coal price 

are from the IPM 5.13 base case for 2020. 

120 8760 hours/year * 78% utilization * 0.976 

metric tons/Mwh * 6% improvement * 0.001 MW/ 

kW = 0.40 metric tons of CO2 per kW-year. The 

estimated average coal-fired EGU CO2 emission rate 

per MWh is from the IPM 5.13 base case for 2020. 

121 $7.75 per metric ton of CO2 * 6%/4% = $11.63 

per metric ton of CO2. 

122 $11.63 per metric ton of CO2 * $50/$100 = 

$5.81 per metric ton of CO2. 

123We note that although we expect that heat rate 

improvements are also available from other fossil 

Continued 

technical potential to reduce heat rate 

variability discussed above was based 

on gross heat rate data. Like gross heat 

rate, parasitic load can be addressed 

both through adoption of best practices 

and through equipment upgrades, and 

some measures undertaken at EGUs may 

affect parasitic load as well as gross heat 

rate. Because the hourly generation data 

reported to the EPA represent gross 

generation, we have less data available 

to directly analyze potential net heat 

rate improvements than gross heat rate 

improvements. We have therefore not 

included any separate estimate of 

parasitic load reductions achievable 

through best practices in our goalsetting data inputs. However, these 

opportunities would be available as a 

mechanism for reducing carbonintensity at affected EGUs and thus 

provide more flexibility and 

opportunities for sources to improve 

their heat rates at reasonable costs.118

The total of the estimated potential 

heat rate improvements from adoption 

of best practices to reduce heat rate 

variability and implementation of 

equipment upgrades as discussed above 

is six percent. This total is used as the 

data input for heat rate improvements in 

the computation of proposed state goals 

discussed in Section VII.C below. 

Because of the close relationship 

between an EGU’s fuel consumption 

and its CO2 emissions, a six percent heat 

rate improvement would be associated 

with a reduction in CO2 emissions of 

approximately six percent. We believe 

that this represents a reasonable 

estimate of the technical potential for 

CO2 emission reductions that would be 

achievable from affected coal-fired 

steam EGUs, on average, through heat 

rate improvements as an element of the 

best system of emission reduction. 

For purposes of developing the 

alternate set of goals on which we are 

taking comment, as described in Section 

VII.E below, we have used a more 

conservative estimate of a four percent 

heat rate improvement from affected 

coal-fired EGUs on average. This level of 

improvement would be consistent with 

those EGUs on average implementing 

best practices to reduce heat rate 

variability without making further 

equipment upgrades, or would be 

consistent with those EGUs on average 

implementing both best practices and 

equipment upgrades, but to a lesser 

degree than we have projected as being 

achievable for purposes of our proposal. 

We view the four percent estimate as a 

reasonable minimum estimate of the 

technical potential for heat rate 

improvement on average across affected 

coal-fired steam EGUs. 

c. Costs of Heat Rate Improvements 

By definition, any heat rate 

improvement made for the purpose of 

reducing CO2 emissions will also reduce 

the amount of fuel the EGU consumes 

to produce its electricity output. The 

cost attributable to CO2 emission 

reductions therefore would be the net 

cost to achieve the heat rate 

improvement after any savings from 

reduced fuel expense. As summarized 

below, we estimate that, on average, the 

savings in fuel cost associated with a six 

percent heat rate improvement would be 

sufficient to cover much of the 

associated costs, with the result that the 

net costs of heat rate improvements 

associated with reducing CO2 emissions 

from affected EGUs are relatively low. 

The EPA’s most detailed estimates of 

the average costs required to achieve the 

full range of heat rate improvements 

come from the 2009 Sargent & Lundy 

study discussed above. Based on the 

study, the EPA estimated that for a 

range of heat rate improvements from 

415 to 1205 Btus per kWh, 

corresponding to percentage heat rate 

improvements of 4 to 12 percent for a 

typical coal-fired EGU, the required 

capital costs would range from $40 to 

$150 per kW. To correspond to the 

average heat rate improvement of six 

percent that we have estimated to be 

achievable through the combination of 

best practices and equipment upgrades, 

we have estimated an average cost of 

$100 per kW, slightly above the 

midpoint of the Sargent & Lundy study’s 

range. At an estimated annual capital 

charge rate of 14.3 percent, the carrying 

cost of an estimated $100 per kW 

investment would be $14.30 per kWyear. For a coal-fired EGU with a heat 

rate of 10,450 Btu per kWh, a utilization 

rate of 78 percent, and a coal price of 

$2.62 per MMBtu, a six percent heat rate 

improvement would produce fuel cost 

savings of approximately $11.20 per 

kW-year,119 leaving approximately 

$3.10 per kW-year of carrying cost not 

recovered through fuel cost savings. At 

an average CO2 emission rate of 0.976 

metric tons per MWh, the same six 

percent heat rate improvement would 

reduce CO2 emissions by 0.40 metric 

tons per kW-year.120 Thus, the average 

cost of CO2 reductions from heat rate 

improvements would be approximately 

$7.75 per metric ton of CO2 ($3.10/0.40). 

If the average heat rate improvement 

achievable for the $100 per kW 

investment were only four percent, 

consistent with the heat rate 

improvement estimate in the alternate 

goals on which we seek comment, the 

average cost of CO2 reductions would be 

$11.63 per metric ton.121 On the other 

hand, if an average heat rate 

improvement of four percent could be 

achieved for an average investment of 

$50 per kW, reflecting an assumption 

that the first improvements pursued 

would be the least expensive ones, the 

average cost of CO2 reductions would 

fall to $5.81 per metric ton.122

The EPA recognizes that the 

simplified cost analysis just described 

will represent the costs for some EGUs 

better than others because of differences 

in EGUs’ individual circumstances. We 

further recognize that reductions in the 

utilization rates of coal-fired EGUs 

anticipated from other components 

proposed for inclusion in the best 

system of emission reduction would 

tend to reduce the fuel savings 

associated with heat rate improvements, 

thereby raising the effective cost of 

achieving the CO2 emission reductions 

from the heat rate improvements. 

Nevertheless, we still expect that the 

majority of the investment required to 

capture the technical potential for CO2

emission reductions from heat rate 

improvements would be offset by fuel 

savings, and that the net costs of heat 

rate improvements as an approach to 

reducing CO2 emissions from existing 

fossil fuel-fired EGUs are reasonable. 

Based on the analyses of technical 

potential and cost summarized above, 

we propose to find that a six percent 

reduction in the CO2 emission rate of 

the coal-fired EGUs in a state, on 

average, is a reasonable estimate of the 

amount of heat rate improvement that 

can be implemented at a reasonable 

cost.123


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34862 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

fuel-fired EGUs, we have conservatively not 

included CO2 emission rate reductions for those 

EGUs in the state goals. However, as discussed in 

Section VI.C.5.d below, we are requesting comment 

on this aspect of the proposal. Further, states and 

sources would be free to use heat rate 

improvements at those other units to help reach the 

state goals. 

124The PJM market monitor publishes 

breakdowns of wholesale energy prices, including 

a CO2 emission allowance cost component, based 

on analysis of the prices bid by the ‘‘marginal’’ 

EGUs. See Monitoring Analytics, 2013 State of the 

Market Report for PJM at 103–05, tbls. 3–63 & 3– 

64 (2014), available at http:// 

www.monitoringanalytics.com/reports/ 

pjm_state_of_the_market/2013.shtml. 

We invite comment on all aspects of 

our analyses and findings related to heat 

rate improvements, both as summarized 

here and as further discussed in the 

Greenhouse Gas Abatement Measures 

TSD. As noted earlier, we specifically 

request comment on increasing the 

estimates of the amounts of heat rate 

improvement achievable through 

adoption of best practices for operation 

and maintenance and through 

equipment upgrades up to six percent 

and four percent, respectively, 

representing a total potential 

improvement of up to ten percent, 

particularly in light of the reasonable 

cost of heat rate improvements. We also 

solicit comment on the quantitative 

impacts on the net heat rates of coalfired steam EGUs of operation at loads 

less than the rated maximum unit loads. 

2. Building Block 2—Dispatch Changes 

Among Affected EGUs 

The second element of the foundation 

for the EPA’s BSER determination for 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs goes to the 

achievement of reductions in mass 

emissions at certain affected EGUs—in 

particular, fossil fuel-fired steam 

EGUs—and entails an analysis of the 

extent to which generation at the most 

carbon-intensive affected EGUs—again, 

in particular, fossil fuel-fired steam 

EGUs—can be replaced with generation 

at less carbon-intensive affected fossil 

fuel-fired EGUs—in particular, NGCC 

units that were in operation or had 

commenced construction as of January 

8, 2014, and are therefore affected units 

for purposes of this rule. 

a. Ability of Re-Dispatch To Reduce CO2

Emissions 

The nation’s EGUs are interconnected 

by transmission grids extending over 

large regions. EGU owners and grid 

operators, subject to various reliability 

and operational constraints, use the 

flexibility provided by these 

interconnections to prioritize among 

available EGUs when deciding which 

units should be called upon (i.e., 

‘‘dispatched’’) to increase or decrease 

generation in order to meet electricity 

demand at any point in time. 

Recognizing that increments of 

generation are to some extent 

interchangeable, dispatch decisions are 

based on electricity demand at a given 

point in time, the variable costs of 

available generating resources, and 

system constraints. This system of 

security-constrained economic dispatch 

assures reliable and affordable 

electricity. Electricity demand varies 

across geography and time in response 

to numerous conditions, such that EGU 

owners and grid operators are 

constantly responding to changes in 

demand and ‘‘re-dispatching’’ to meet 

demand in the most reliable and costeffective manner possible. Since the 

enactment and implementation of Title 

IV of the CAA Amendments of 1990, in 

regions where EGUs are subject to 

market-based programs to limit 

emissions of pollutants such as SO2 and 

NOX, the costs of emission allowances 

have been factored directly into those 

EGUs’ variable costs, like the variable 

costs of operating pollution control 

devices, and have thereby been 

accounted for in least-cost economic 

dispatch decisions by grid operators. 

Similarly, operators of EGUs subject to 

CO2 emissions limits in RGGI now 

include the cost of RGGI CO2

allowances in those EGUs’ variable 

costs,124 creating economic incentives to 

replace generation at higher-emitting 

EGUs with generation from loweremitting sources to reduce CO2

emissions at the former through the 

process of least-cost economic dispatch. 

As an alternate mechanism, permitting 

authorities can impose limits on 

utilization or CO2 emissions at higheremitting EGUs, in which case grid 

operators and other market participants 

would use the integrated electricity 

system to find other ways to meet the 

demand for electricity services, either 

through demand-side energy efficiency 

or through increased generation from 

lower-emitting EGUs. In either case, 

whether implemented through 

economic mechanisms or permit 

limitations, reducing emissions at high 

carbon-intensity EGUs is technically 

feasible and can reduce overall power 

sector CO2 emissions because generation 

at such EGUs can be replaced by 

generation at less carbon-intensive 

EGUs. 

We have also analyzed potential 

upstream net methane emissions impact 

from natural gas and coal for the 

impacts analysis. This analysis 

indicated that any net impacts from 

methane emissions are likely to be small 

compared to the CO2 emissions 

reduction impacts of shifting power 

generation from coal-fired steam EGUs 

to NGCC units. Further information on 

our analysis of upstream impacts can be 

found in Appendix 3A of the RIA. 

b. Magnitude of Re-Dispatch 

Having identified replacing 

generation at higher-emitting EGUs with 

generation at lower-emitting EGUs as a 

technically feasible CO2 emissions 

reduction strategy, we next address the 

quantity of replacement generation that 

may be relied upon at reasonable costs. 

The U.S. electric generating fleet 

includes EGUs employing a variety of 

generating technologies. EGUs using 

technologies with relatively low 

variable costs, such as nuclear units, are 

for economic reasons generally operated 

at their maximum output whenever they 

are available. Renewable EGUs such as 

wind and solar units also have low 

variable costs, but in any event are 

generally operated when wind and sun 

conditions permit rather than at 

operators’ discretion. In contrast, fossil 

fuel-fired EGUs have higher variable 

costs and are also relatively flexible. 

Fossil fuel-fired EGUs are therefore 

generally the units that operators use to 

respond to intra-day and intra-week 

changes in demand. Because of these 

typical characteristics of the various 

EGU types, the primary re-dispatch 

opportunities among existing units 

available to EGU owners and grid 

operators generally consist of 

opportunities to shift generation among 

various fossil fuel-fired units, in 

particular between coal-fired EGUs (as 

well as oil- and gas-fired steam EGUs) 

and NGCC units. In the shortterm—that 

is, over time intervals shorter than the 

time required to build a new EGU— 

fossil fuel-fired units consequently tend 

to compete more with one another than 

with nuclear and renewable EGUs. The 

amount of re-dispatch from coal-fired 

EGUs to NGCC units that takes place as 

a result of this competition is highly 

relevant to overall power sector GHG 

emissions, because a typical NGCC unit 

produces less than half as much CO2 per 

MWh of electricity generated as a 

typical coal-fired EGU. 

In order to estimate the potential 

magnitude of the opportunity to reduce 

power sector CO2 emissions through redispatch among existing EGUs, the EPA 

first examined information on the 

design capabilities and availability of 

NGCC units. This examination showed 

that, although most NGCC units have 

historically been operated in 

intermediate-duty roles for economic 

reasons, they are technically capable of 


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125See, e.g., North American Electric Reliability 

Corp., 2008–2012 Generating Unit Statistical 

Brochure—All Units Reporting, http://

www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; 

Higher Availability of Gas Turbine Combined Cycle, 

Power Engineering (Feb. 1, 2011), http://

www.power-eng.com/articles/print/volume-115/

issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html. 

126Today in Energy, EIA (June 6, 2012) (http://

www.eia.gov/todayinenergy/detail.cfm?id=6990). 

127The corresponding percentages of NGCC units 

that in 2012 operated at annual utilization rates of 

at least 65 percent and at least 75 percent were 16 

percent and 6 percent, respectively. 

128Air Markets Program Data (at http://

ampd.epa.gov/ampd/). 

129See Section VII for further explanation of how 

goals were computed. 

130For covered sources. 

131See Greenhouse Gas Emission Reductions 

From Existing Power Plants: Options to Ensure 

Electric System Reliability (Analysis Group, Inc., 

May 2014). Also see the Resource Adequacy 

Technical Support Document. 

132EIA, Average utilization of the nation’s natural 

gas combined-cycle power plant fleet is rising, 

Today in Energy, July 9,2011, http://www.eia.gov/ 

todayinenergy/detail.cfm?id=1730#; EIA, Today in 

Energy, Jan. 15, 2014, http://www.eia.gov/

todayinenergy/detail.cfm?id=14611 (for recent 

data). 

133EIA, Electric Power Monthly, February, 2014. 

Table 6.7.A. 

operating in base-load roles at much 

higher annual utilization rates. Average 

annual availability (that is, the 

percentage of annual hours when an 

EGU is not in a forced or maintenance 

outage) for NGCC units in the U.S. 

generally exceeds 85 percent, and can 

exceed 90 percent for some groups.125

We also researched historical data to 

determine the utilization rates that 

NGCC units have already been 

demonstrated capable of sustaining. 

Over the last several years, EGU owners 

and grid operators have engaged in 

considerable re-dispatch among various 

types of fossil fuel-fired units relative to 

historical dispatch patterns, with NGCC 

units increasing generation and many 

coal-fired EGUs reducing generation. In 

fact, in April 2012, for the first time ever 

the total quantity of electricity generated 

nationwide from natural gas was 

approximately equal to the total 

quantity of electricity generated 

nationwide from coal.126 These changes 

in generation patterns have been driven 

largely by changes over time in the 

relative prices of natural gas and coal, 

in addition to lower overall demand for 

electricity. Although the relative fuel 

prices vary by location, as do the recent 

patterns of re-dispatch, this trend holds 

across broad regions of the U.S. In the 

aggregate, the historical data provide 

ample evidence indicating that, on 

average, existing NGCC units can 

achieve and sustain utilization rates 

higher than their present utilization 

rates. 

The experience of relatively heavily 

used NGCC units provides an additional 

indication of the degree of increase in 

average NGCC unit utilization that is 

technically feasible. According to the 

historical NGCC unit utilization rate 

data reported to the EPA, in 2012 

roughly 10 percent of existing NGCC 

units operated at annual utilization rates 

of 70 percent or higher.127 In effect, 

these units were being dispatched to 

provide base-load power. In addition to 

the 10 percent of NGCC units that 

operated at a 70 percent utilization rate 

on an annual basis, some NGCC units 

operated at high utilization rates for 

shorter, but still sustained, periods of 

time in response to high cyclical 

demand. For example, on a seasonal 

basis, a significant number of NGCC 

units have achieved utilization rates 

between 50 and 80 percent; over the 

2012 winter season (December 2011– 

February 2012) and summer season 

(June–August 2012), about 16 percent 

and 19 percent of NGCC units, 

respectively, operated at utilization 

rates of 70 percent or more across these 

entire seasons.128 During the spring and 

fall periods when electricity demand 

levels are typically lower, these units 

were sometimes idled or operated at 

much lower capacity factors. 

Nonetheless, the data clearly 

demonstrate that a substantial number 

of existing NGCC units have proven the 

ability to sustain 70 percent utilization 

rates for extended periods of time. We 

view this as strong evidence that 

increasing the utilization rates of 

existing NGCC units to 70 percent, not 

in every individual instance but on 

average, as part of a comprehensive 

approach to reducing CO2 emissions 

from existing high carbon-intensity 

EGUs, would be technically feasible. 

For purposes of establishing state 

goals, historical (2012) electric 

generation data are used to apply each 

building block and develop each state’s 

goal (expressed as an adjusted CO2

emission rate in lbs per MWh).129 In 

2012, total electric generation from 

existing NGCC units was 959 TWh.130

After the application of NGCC redispatch toward a 70 percent target 

utilization rate, the total generation from 

these existing sources is projected to be 

1,390 TWh per year. Adding in the 

NGCC units that had commenced 

construction before January 8, 2014 (and 

are therefore existing sources for 

purposes of this proposal) but were not 

yet in operation in 2012 increases the 

projected total generation from the full 

set of existing NGCC units to 1,443 TWh 

per year. 

Although producing over 1,400 TWh 

of generation in 2020 from existing 

NGCC units is not actually required, 

because states may choose other 

abatement measures to reach the state 

goals, the EPA nevertheless believes that 

producing this quantity of generation 

from this set of NGCC units is feasible. 

As a reference point, NGCC generation 

increased by approximately 430 TWh 

(an 80 percent increase) between 2005 

and 2012. The EPA calculates that 

NGCC generation in 2020 could increase 

by approximately 50 percent from 

today’s levels. This reflects a smaller 

ramp-up rate in NGCC generation than 

has been observed from 2005 to 2012. 

We also expect an increase in NGCC 

generation of this amount would not 

impair power system reliability. As we 

note in the TSD on Resource Adequacy 

and Reliability, the level of potential redispatch can be accommodated within 

the flexible compliance requirements of 

the rule. Similar conclusions have been 

reached in recent studies of the 

potential impact of emission reductions 

from existing power plants.131

The EPA also examined the technical 

capability of the natural gas supply and 

delivery system to provide increased 

quantities of natural gas and the 

capability of the electricity transmission 

system to accommodate shifting 

generation patterns. For several reasons, 

we conclude that these systems would 

be capable of supporting the degree of 

increased NGCC utilization needed for 

states to achieve the proposed goals. 

First, the natural gas pipeline system is 

already supporting national average 

NGCC utilization rates of 60 percent or 

higher during peak hours, which are the 

hours when constraints on pipelines or 

electricity transmission networks are 

most likely to arise. NGCC unit 

utilization rates during the range of peak 

daytime hours from 10 a.m. to 9 p.m. are 

typically 15 to 20 percentage points 

above their average utilization rates 

(which have recently been in the range 

of 40 to 50 percent).132 Fleet-wide 

combined-cycle average monthly 

utilization rates have reached 65 

percent,133 showing that the pipeline 

system can currently support these rates 

for an extended period. If the current 

pipeline and transmission systems 

allow these utilization rates to be 

achieved in peak hours and for 

extended periods, it is reasonable to 

expect that similar utilization rates 

should also be possible in other hours 

when constraints are typically less 

severe, and be reliably sustained for 

other months of the year. The second 

consideration supporting our view that 

natural gas and electricity system 


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134See, e.g., EIA, Natural Gas Pipeline Additions 

in 2011, Today in Energy; INGAA Foundation, 

Pipeline and Storage Infrastructure Requirements 

for a 30 Tcf Market (2004 update); INGAA 

Foundation, North American Midstream 

Infrastructure Through 2035—A Secure Energy 

Future Report (2011). 

135Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market, INGAA 

Foundation, 1999 (Updated July, 2004); U.S. gas 

groups confident of 30-tcf market, Oil and Gas 

Journal, 1999. 

136For example, between 2010 and April 2014, 

118 pipeline projects with 44,107 MMcf/day of 

capacity (4,699 miles of pipe) were placed in 

service, and between April 2014 and 2016 an 

additional 47 pipeline projects with 20,505 MMcf/ 

day of capacity (1,567 miles of pipe) are scheduled 

for completion. Energy Information Administration, 

http://www.eia.gov/naturalgas/data.cfm. 

137According to the Edison Electric Institute, 

member companies are planning over 170 projects 

through 2024, with costs totaling approximately 

$60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent of the reported projects (over 

13,000 line miles) are high voltage (345 kV and 

higher). http://www.eei.org/issuesandpolicy/

transmission/Documents/Trans_Project_lowres_

bookmarked.pdf. 

138See Section VII.D and Section VIII below for 

discussion of timing flexibility. 

139See Chapter 3 of the Regulatory Impact 

Analysis for more detail. 

infrastructure would be capable of 

supporting increased NGCC unit 

utilization rates is the flexibility of the 

emission guidelines. The state goals do 

not require any particular NGCC unit 

utilization rate to be achieved in any 

hour or year of the initial plan period. 

Thus, even if isolated natural gas or 

electricity system constraints were to 

limit NGCC unit utilization rates in 

certain locations in certain hours, this 

would not prevent an increase in NGCC 

generation overall across a state or 

broader region and across all hours. The 

third consideration supporting a 

conclusion regarding the adequacy of 

the infrastructure is that pipeline and 

transmission planners have repeatedly 

demonstrated the ability to 

methodically relieve bottlenecks and 

expand capacity.134 Natural gas pipeline 

capacity has regularly been added in 

response to increased gas demand and 

supply, such as the addition of large 

amounts of new NGCC capacity from 

2001 to 2003, or the delivery to market 

of unconventional gas supplies since 

2008. These pipeline capacity increases 

have added significant deliverability to 

the natural gas pipeline network to meet 

the potential demands from increased 

use of existing NGCC units. Over a 

longer time period, much more 

significant pipeline expansion is 

possible. In previous studies, when the 

pipeline system was expected to face 

very large demands for natural gas use 

by electric utilities about ten years ago, 

increases of up to 30 percent in total 

deliverability out of the pipeline system 

were judged to be possible by the 

pipeline industry.135 There have been 

notable pipeline capacity expansions 

over the past five years, and substantial 

additional pipeline expansions are 

currently under construction.136

Similarly, the electric transmission 

system is undergoing substantial 

expansion.137 Further, as discussed 

below in Sections VII.D and VIII of this 

preamble (on state flexibilities and state 

plans, respectively), we believe the 

flexible nature of the proposed goals 

provides time for infrastructure 

improvements to occur should they 

prove necessary in some locations.138

Combining these factors of currently 

observed average monthly NGCC 

utilization rates of up to 65 percent, the 

flexibility of the emission guidelines, 

and the availability of time to address 

any existing infrastructure limitations, it 

is reasonable to conclude that the 

natural gas pipeline system can reliably 

deliver sufficient natural gas supplies, 

and the electric transmission system can 

reliably accommodate changed 

generation patterns, to allow NGCC 

utilization to increase up to an average 

annual utilization rate of 70 percent. 

We recognize that re-dispatch does 

contemplate an associated increase in 

natural gas production, consistent with 

the current trends in the natural gas 

industry. The EPA expects the growth in 

NGCC generation assumed in goalsetting to be feasible and consistent with 

domestic natural supplies. Increases in 

the natural gas resource base have led to 

fundamental changes in the outlook for 

natural gas. There is general agreement 

that recoverable natural gas resources 

will be substantially higher for the 

foreseeable future than previously 

anticipated, exerting downward 

pressure on natural gas prices. 

According to EIA, proven natural gas 

reserves have doubled between 2000 

and 2012. Domestic production has 

increased by 32 percent over that same 

timeframe (from 19.2 TCF in 2000 to 

25.3 TCF in 2012). EIA’s Annual Energy 

Outlook for 2014 projects that 

production will further increase to 29.1 

TCF, as a result of increased supplies 

and favorable market conditions. For 

comparison, NGCC generation growth of 

450 TWh (calculated in goal setting) 

would result in increased gas 

consumption of roughly 3.5 TCF for the 

electricity sector, which is less than the 

projected increase in natural gas 

production. 

The EPA notes that the assessments 

described above regarding the ability of 

the electricity and natural gas industries 

to achieve the levels of performance 

indicated for building block 2 in the 

state goal computations are supported 

by analysis that has been conducted 

using the Integrated Planning Model 

(IPM). IPM is a multi-regional, dynamic, 

deterministic linear programming model 

of the U.S. electric power sector that the 

EPA has used for over two decades to 

evaluate the economic and emission 

impacts of prospective environmental 

policies. To fulfill its purpose of 

producing projections related to the 

electric power sector and its related 

markets—including least-cost capacity 

expansion and electricity dispatch 

projections—that reflect industry 

conditions in as realistic a manner as 

possible, IPM incorporates 

representations of constraints related to 

fuel supply, transmission, and unit 

dispatch. The model includes a detailed 

representation of the natural gas 

pipeline network and the capability to 

project economic expansion of the 

network based on pipeline load factors. 

At the EGU level, IPM includes detailed 

representations of key operational 

limitations such as turn-down 

constraints, which are designed to 

account for the cycling capabilities of 

EGUs to ensure that the model properly 

reflects the distinct operating 

characteristics of peaking, cycling, and 

base load units. 

As described in more detail below, 

the EPA used IPM to assess the costs of 

requiring increasing levels of redispatch from higher- to lower-emitting 

EGUs, and to that end, the EPA 

developed a series of modeling 

scenarios that explored shifting 

generation from existing coal-fired EGUs 

to existing NGCC units on a 1:1 basis 

within defined areas.139 By the nature of 

IPM’s design, those scenarios 

necessarily also require compliance 

with the constraints just described (as 

implemented for any specific scenario). 

IPM was able to arrive at a solution for 

scenarios reflecting average NGCC 

utilization rates of 65, 70, and 75 

percent, while observing the market, 

technical, and regulatory constraints 

embedded in the model. Such a result 

is consistent with the EPA’s 

determination that increasing the 

utilization rates of existing NGCC units 

to 70 percent, not in every individual 

instance but on average, as part of a 

comprehensive approach to reducing 

CO2 emissions from existing high 

carbon-intensity EGUs, would be 

technically feasible. 

c. Cost of Re-Dispatch 

Having established the technical 

feasibility and quantification of 

replacing incremental generation at 


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140See Regulatory Impact Analysis for more 

detail. 

141The utilization rate constraint applied on 

average to all NGCC units nationwide and did not 

apply to individual NGCC units or to the fleets of 

NGCC units within individual states. 

142To best reflect the integrated nature of the 

electric power sector, the EPA defined six regions 

for this analysis, the borders of which are informed 

by North American Electric Reliability (NERC) 

regions and Regional Transmission Organizations 

(RTOs). See Chapter 3 of the Regulatory Impact 

Analysis for more detail. 

143The analogous costs for the scenarios with 65 

and 75 percent NGCC utilization rates were $21 and 

$40 per metric ton of CO2, respectively. For further 

detail on cost methodology, data inputs, and 

results, refer to Chapter 3 of the GHG Abatement 

Measures TSD. 

144For further explanation of the state goal 

computation methodology, see Section VII of the 

preamble and the Goal Computation TSD. 

145According to EIA data, year-to-year changes in 

natural gas prices at Henry Hub averaged 29.9 

percent over the period from 2000 to 2013. 

http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm. 

146For example, year-on-year changes in PJM 

wholesale electricity prices averaged 19.5 percent 

Continued 

higher-emitting EGUs with generation at 

NGCC facilities as a CO2 emissions 

reduction strategy, we next turn to the 

question of cost. The cost of the power 

sector CO2 emission reductions that can 

be achieved through re-dispatch among 

existing fossil fuel-fired EGUs depends 

on the relative variable costs of 

electricity production at EGUs with 

different degrees of carbon intensity. 

These variable costs are driven by the 

EGUs’ respective fuel costs and by the 

efficiencies with which they can convert 

fuel to electricity (i.e., their heat rates). 

Historically, natural gas has had a 

higher cost per unit of energy content 

(e.g., MMBtu) than coal in most 

locations, but for NGCC units this 

disadvantage in fuel cost per MMBtu 

relative to coal-fired EGUs is typically 

offset in significant part, and sometimes 

completely, by a heat rate advantage. 

The EPA has conducted two sets of 

extensive analyses to help inform the 

development of the state-specific 

emission goals described in this 

proposal, including analyses of the 

opportunity to reduce CO2 emissions 

through re-dispatch. The first set was a 

dispatch-only set that provided a 

framework for understanding the 

broader economic and emissions 

implications of shifting generation to 

NGCC units from more carbon-intensive 

EGUs without consideration of emission 

reduction measures reflected in the 

other building blocks. The second set 

included additional refinements and 

more closely reflected all the 

characteristics of the proposed goals 

that were used as the basis for assessing 

the costs and benefits of the overall 

proposal.140 Both sets of analyses were 

conducted using IPM. 

The first set—the dispatch-only 

analyses—explored the magnitude and 

cost of potential opportunities to shift 

generation from existing coal-fired EGUs 

to existing NGCC units within defined 

areas. The purpose of analyzing these 

scenarios was to understand and 

demonstrate to what extent existing 

NGCC units could increase their 

dispatch at reasonable costs and without 

significant impacts on other economic 

variables such as the prices of natural 

gas and electricity. To evaluate how 

EGU owners and grid operators could 

respond to a state plan’s possible 

requirements, signals, or incentives to 

re-dispatch from more carbon-intensive 

to less carbon-intensive EGUs, the EPA 

analyzed a series of scenarios in which 

the fleet of NGCC units nationwide was 

required, on average, to achieve a 

specified annual utilization rate.141

Specifically, the scenarios required 

average NGCC unit utilization rates of at 

least 65, 70, and 75 percent, 

respectively. For each scenario, we 

identified the set of dispatch decisions 

that would meet electricity demand at 

the lowest total cost, subject to all other 

specified operating and reliability 

constraints for the scenario, including 

the specified average NGCC unit 

utilization rate. Further, we allowed redispatch to occur exclusively within a 

region’s existing fleet.142

The costs and economic impacts of 

the various scenarios were evaluated by 

comparing the total costs and emissions 

from each scenario to the costs and 

emissions from a business-as-usual 

scenario. For the scenario reflecting a 70 

percent NGCC utilization rate, 

comparison to the business-as-usual 

case indicates that the average cost of 

the CO2 reductions achieved over the 

2020–2029 period was $30 per metric 

ton of CO2.143 We view these estimated 

costs as reasonable and therefore as 

supporting the use of a 70 percent 

utilization rate target for purposes of 

quantifying the emission reductions 

achievable at a reasonable cost through 

the application of the BSER. 

However, we also note that the costs 

just described are higher than we would 

expect to actually occur in real-world 

compliance with this proposal’s goals. 

One reason for this is that the 70 percent 

utilization rate in the scenario 

exaggerates the stringency with which 

building block 2 is actually reflected in 

each of the state goals: While the goal 

computation procedure uses 70 percent 

as a target NGCC utilization rate for all 

states, for only 29 states do the goals 

actually reflect reaching that target 

NGCC utilization, with the result that 

the average NGCC utilization rate 

reflected in the computed state goals is 

only 64 percent.144 Also, at least some 

states may be able to achieve additional 

emission reductions through other 

components of the BSER, and those 

other components may be relatively 

inexpensive. The dispatch-only analyses 

were focused on evaluating the potential 

impacts of re-dispatch in particular, and 

as a result, they reflect an assumption 

that even in a state where re-dispatch 

might be relatively expensive compared 

to other available CO2 emission 

reduction measures that are part of the 

BSER, the state plan would rely on redispatch to the same extent as the plans 

of other states. In practice, under these 

circumstances, states would have 

flexibility to choose among alternative 

CO2 reduction strategies that were part 

of the BSER, instead of relying on redispatch to the maximum extent. 

The EPA also analyzed dispatch-only 

scenarios where shifting of generation 

among EGUs was limited by state 

boundaries. In these scenarios with less 

re-dispatch flexibility, the cost of 

achieving the quantity of CO2

reductions corresponding to a 

nationwide average NGCC unit 

utilization of 70 percent was $33 per 

metric ton. Combining the results of the 

modeling with the factors likely to be 

present in the real world reinforces the 

support we expressed above for the 70 

percent utilization rate. We remain 

concerned, however, that higher NGCC 

utilization rates could be harder to 

sustain and could exert further upward 

pressure on prices. 

We invite comment on whether the 

regional or state scenarios should be 

given greater weight in establishing the 

appropriate degree of re-dispatch to 

incorporate into the state goals for CO2

emission reductions, and in assessing 

costs. 

We also conclude from our analyses 

that the extent of re-dispatch estimated 

in this building block can be achieved 

without causing significant economic 

impacts. For example, in both of the 70 

percent NGCC unit utilization rate 

scenarios—with re-dispatch limited to 

regional and state boundaries, 

respectively—delivered natural gas 

prices were projected to increase by an 

average of no more than ten percent 

over the 2020–2029 period, which is 

well within the range of historical 

natural gas price variability.145

Projected wholesale electricity price 

increases over the same period were less 

than seven percent in both cases, which 

similarly is well within the range of 

historical electric price variability.146


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over the period from 2000 to 2013. Ventyx Velocity 

Suite, ISO real-time data for all hours. Price 

variability for other eastern ISO regions (NYISO, 

ISO–NE., and Midcontinent ISO) was similar. Id. 

147For further analysis related to the use of a 75 

percent target utilization rate for NGCC units, see 

chapter 3 of the GHG Abatement Measures TSD. 

148 Database of State Incentives for Renewables & 

Efficiency (DSIRE), http://www.dsireusa.org/

summarymaps/index.cfm?ee=0&RE=0. 

149For discussion of how states and sources 

might use RE in state plans, see Section VIII below. 

150The EPA recognizes that individual RPS 

policies vary in their specification of where 

qualifying RE generation must occur. However, the 

EPA believes the regional structure of this 

estimation exercise supports a broad interpretation 

of RPS requirements across states within a region 

as a proxy for reasonable-cost RE generation 

potential within the same region. 

We view these projected impacts as not 

unreasonable and as supporting use of 

a 70 percent NGCC utilization rate target 

for purposes of quantifying the emission 

reductions achievable through 

application of the BSER. 

However, for the same reasons 

discussed above with respect to 

estimated costs per ton of CO2, in actual 

implementation we again expect that 

the economic impacts shown in these 

scenarios, including natural gas price 

impacts, are likely overstated compared 

to the impacts that would actually occur 

in real-world compliance with this 

rule’s proposed goals. Consistent with 

this expectation, the comprehensive 

analyses used to assess the compliance 

costs and benefits of this proposal, 

which reflect a more complete 

representation of the additional 

flexibility available to states, show 

significantly smaller economic impacts. 

These analyses are discussed in Section 

X below. 

Based on the analyses summarized 

above, the EPA proposes that for 

purposes of establishing state goals, a 

reasonable estimate regarding the degree 

of mass emission reductions achievable 

at fossil fuel-fired steam EGUs can be 

determined based on the degree to 

which electricity generation could be 

shifted from more carbon-intensive 

EGUs to less carbon-intensive EGUs 

within the state at reasonable cost 

through re-dispatch. The increment of 

emission reductions incorporated in this 

component of our proposed BSER 

determination is commensurate with an 

annual utilization rate for the state’s 

NGCC units of up to 70 percent, on 

average across all the NGCC units in the 

state. 

For purposes of the alternative set of 

goals on which we are seeking 

comment, we have used the less 

stringent target of a 65 percent average 

utilization rate for NGCC units. In 2012, 

approximately 16 percent of existing 

NGCC plants larger than 25 megawatts 

had utilization rates equal to or higher 

than this level. Also, as noted earlier, 

average NGCC utilization nationwide is 

already over 60 percent in some peak 

hours. We therefore view 65 percent as 

a reasonable lower-bound estimate of an 

achievable average NGCC utilization 

rate, and we would expect the costs and 

economic impacts from re-dispatch 

associated with a 65 percent NGCC 

utilization target to be lower than the 

costs and impacts associated with the 70 

percent utilization target. Our cost 

analysis indicated that CO2 emission 

reductions consistent with a 65 percent 

average NGCC utilization rate could be 

achieved at a cost of $21 per metric ton. 

As discussed above, in addition to 

analyzing the impacts of using the 

proposed 70 percent target utilization 

rate for existing NGCC units, the EPA 

has also performed preliminary analysis 

of the impacts of using a target 

utilization rate for existing NGCC units 

of 75 percent. That analysis showed that 

CO2 emission reductions consistent 

with a 75 percent target utilization rate 

could be achieved at a cost of $40 per 

metric ton.147 We invite comment on 

whether we should consider options for 

a target utilization rate for existing 

NGCC units greater than the proposed 

70 percent target utilization rate. 

We invite comment on these proposed 

findings and on all other issues raised 

by the discussion above and the related 

portions of the Greenhouse Gas 

Abatement Measures TSD. 

3. Building Block 3—Using an 

Expanded Amount of Less CarbonIntensive Generating Capacity 

The third element of the foundation 

for the EPA’s BSER determination for 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs also goes to the 

achievement of reductions in mass 

emissions, but in this case the 

reductions would occur at all affected 

EGUs, and entails an analysis of the 

extent to which generation at the 

affected EGUs can be replaced by using 

an expanded amount of lower-carbon 

generating capacity to produce 

replacement generation. Below we 

discuss two types of generating capacity 

that can play this role: Renewable 

generating capacity and new and 

preserved nuclear capacity. 

a. Renewable Generating Capacity 

Renewable electricity (RE) generating 

technologies are a well-established part 

of the U.S. power sector. In 2012, 

electricity generated from renewable 

technologies, including conventional 

hydropower, represented 12 percent of 

total U.S. electricity generation, up from 

9 percent in 2005. More than half the 

states have established renewable 

portfolio standards (RPS) that require 

minimum proportions of electricity 

sales to be supplied with generation 

from renewable generating resources.148

Production of this renewable generation 

replaces predominantly fossil fuel-fired 

generation and thereby avoids the CO2

emissions from that replaced generation. 

The EPA believes that renewable 

electricity generation is a proven way to 

assure reductions of CO2 emissions at 

affected EGUs at a reasonable cost.149

1. Proposed Quantification of 

Renewable Energy Generation 

To estimate the CO2 emission 

reductions from affected EGUs 

achievable based on increases in 

renewable generation, the EPA has 

developed a ‘‘best practices’’ scenario 

for renewable energy generation based 

on the RPS requirements already 

established by a majority of states. The 

EPA views the existing RPS 

requirements as a reasonable foundation 

upon which to develop such a scenario 

for two principal reasons. First, in 

establishing the requirements, states 

have already had the opportunity to 

assess those requirements against a 

range of policy objectives including 

both feasibility and costs. These prior 

state assessments therefore support the 

feasibility and cost of the best practices 

scenario as well. Second, renewable 

resource development potential varies 

by region, and the RPS requirements 

developed by the states necessarily 

reflect consideration of the states’ own 

respective regional contexts.150

The EPA has not assumed any 

specific type of renewable generating 

technology for the best practices 

scenario. Also, the scenario is not an 

EPA forecast of renewable capacity 

development and neither establishes 

RPS requirements that any state must 

meet nor makes any determinations 

regarding allowable RE compliance 

measures. Rather, it represents a level of 

renewable resource development for 

individual states—with recognition of 

regional differences—that we view as 

reasonable and consistent with policies 

that a majority of states have already 

adopted based on their own policy 

objectives and assessments of feasibility 

and cost. 

As noted above, renewable resource 

potential varies regionally. This 

geographic pattern is reflected in the 

existing RPS requirements of the various 

states. Recognizing this pattern, the EPA 

has grouped the states into six regions 

for purposes of developing the best 


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151 Given their unique locations, Alaska and 

Hawaii are not grouped with other states into these 

regions. As a conservative approach to estimating 

RE generation potential in Alaska and Hawaii, the 

EPA has developed RE generation targets for each 

of those states based on the lowest values for the 

six regions evaluated here. 

152The regions are the same as those used in 

regional modeling of this rule; see the Regulatory 

Impact Analysis for more information on the 

regional modeling. 

153See Section VIII below for further discussion 

of timing requirements for state plan submittals. 

practices scenario.151 By comparing 

each state to a set of neighbors rather 

than to a single national standard, we 

are able to take regional variation into 

account while still maintaining a level 

of rigor for the scenario’s targets. The 

regional structure is informed by North 

American Electric Reliability 

Corporation (NERC) regions and 

Regional Transmission Organizations 

(RTOs), with adjustments to align 

regional borders with state borders and 

to group Florida and Texas with 

neighboring states.152 This structure 

accounts for similar power system 

characteristics as well as geographic 

similarities in RE potential. The 

grouping of states into the six regions is 

shown in Table 5 below. 

TABLE 5—REGIONS FOR DEVELOPMENT OF BEST PRACTICES RPS SCENARIO

Region States 

East Central ................................. Delaware, District of Columbia*, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia. 

North Central ............................... Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, North Dakota, South Dakota, Wisconsin. 

Northeast ..................................... Connecticut, Maine, Massachusetts, New Hampshire, New York, Rhode Island, Vermont*. 

South Central .............................. Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, Texas. 

Southeast .................................... Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, Tennessee. 

West ............................................ Arizona, California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, Wyoming. 

* Because Vermont and the District of Columbia lack affected sources, no goals are being proposed for these jurisdictions. 

The best practices scenario for each 

state consists of increasing annual levels 

of RE generation estimated based on 

application of an annual RE growth 

factor to the state’s historical RE 

generation, subject to a maximum RE 

generation target. The annual RE growth 

factors and maximum RE generation 

targets were developed separately for 

each of the six regions. Our procedure 

for determining these elements is 

described in the Greenhouse Gas 

Abatement Measures TSD and 

summarized below. 

The EPA first quantified the amount 

of renewable generation in 2012 in each 

state. The EPA then summed these 

amounts for all states in each region to 

determine a regional starting level of 

renewable generation prior to 

implementation of the best practices 

scenario. Hydropower generation is 

excluded from this existing 2012 

generation for purposes of quantifying 

BSER-related RE generation potential 

because building the methodology from 

a baseline that includes large amounts 

of existing hydropower generation could 

distort regional targets that are later 

applied to states lacking that existing 

hydropower capacity. The exclusion of 

pre-existing hydropower generation 

from the baseline of this target-setting 

framework does not prevent states from 

considering incremental hydropower 

generation from existing facilities (or 

later-built facilities) as an option for 

compliance with state goals. 

Next, the EPA estimated the aggregate 

target level of RE generation in each of 

the six regions assuming that all states 

within each region can achieve the RE 

performance represented by an average 

of RPS requirements in states within 

that region that have adopted such 

requirements. For this purpose, the EPA 

averaged the existing RPS percentage 

requirements that will be applicable in 

2020 and multiplied that average 

percentage by the total 2012 generation 

for the region. We also computed each 

state’s maximum RE generation target in 

the best practices scenario as its own 

2012 generation multiplied by that 

average percentage. (For some states that 

already have RPS requirements in place, 

these amounts are less than their RPS 

targets for 2030.) 

For each region we then computed the 

regional growth factor necessary to 

increase regional RE generation from the 

regional starting level to the regional 

target through investment in new RE 

capacity, assuming that the new 

investment begins in 2017, the year 

following the initial state plan 

submission deadline,153 and continues 

through 2029. This regional growth 

factor is the growth factor used for each 

state in that region to develop the best 

practices scenario. 

Finally, we developed the annual RE 

generation levels for each state. To do 

this, we applied the appropriate 

regional growth factor to that state’s 

initial RE generation level, starting in 

2017, but stopping at the point when 

additional growth would cause total RE 

generation for the state to exceed the 

state’s maximum RE generation target. 

For computation of the proposed state 

goals discussed in Section VII.C below, 

we used the annual amounts for the 

years 2020 through 2029. For 

computation of the alternate state goals 

discussed in Section VII.E below, on 

which we are seeking comment, we 

used the annual amounts for the years 

2020 through 2024. 

Alaska and Hawaii are treated as 

separate regions. Their RE targets are 

based on the lowest regional RE target 

among the continental U.S. regions and 

their growth factors are based upon 

historical growth rates in their own RE 

generation. We invite comment 

regarding the treatment of Alaska and 

Hawaii as part of this method. 

For details on the regional targets and 

growth factors applied, please refer to 

Chapter 4 of the GHG Abatement 

Measures TSD. 

The cumulative RE amounts for each 

state, represented as percentages of total 

generation, are shown in Table 6. 


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154 Vermont and the District of Columbia are 

excluded from this table because we are not 

proposing goals for those jurisdictions. 

155 In this proposed RE approach, this situation 

only occurs with the RE targets quantified for the 

state of Washington. 

TABLE 6—STATE RE GENERATION LEVELS FOR STATE GOAL DEVELOPMENT

[Percentage of annual generation]154

State 2012 

percent) 

Proposed goals Alternate goals 

Interim 

level * 

(percent) 

Final 

level 

(percent) 

Interim 

level * 

(percent) 

Final 

level 

(percent) 

Alabama ............................................................................... 2 6 9 4 5 

Alaska .................................................................................. 1 2 2 1 1 

Arizona ................................................................................. 2 3 4 3 3 

Arkansas .............................................................................. 3 5 7 4 5 

California .............................................................................. 15 20 21 20 21 

Colorado ............................................................................... 12 19 21 17 19 

Connecticut .......................................................................... 2 5 9 4 5 

Delaware .............................................................................. 2 7 12 4 5 

Florida .................................................................................. 2 6 10 4 6 

Georgia ................................................................................ 3 8 10 6 7 

Hawaii .................................................................................. 9 10 10 10 10 

Idaho .................................................................................... 16 21 21 21 21 

Illinois ................................................................................... 4 7 9 6 7 

Indiana ................................................................................. 3 5 7 4 5 

Iowa ...................................................................................... 25 15 15 15 15 

Kansas ................................................................................. 12 19 20 19 20 

Kentucky .............................................................................. 0 1 2 1 1 

Louisiana .............................................................................. 2 5 7 4 4 

Maine ................................................................................... 28 25 25 25 25 

Maryland .............................................................................. 2 10 16 6 8 

Massachusetts ..................................................................... 5 15 24 11 13 

Michigan ............................................................................... 3 6 7 5 6 

Minnesota ............................................................................. 18 15 15 15 15 

Mississippi ............................................................................ 3 8 10 6 8 

Missouri ................................................................................ 1 2 3 2 2 

Montana ............................................................................... 5 8 10 6 7 

Nebraska .............................................................................. 4 8 11 6 7 

Nevada ................................................................................. 8 14 18 12 14 

New Hampshire ................................................................... 7 19 25 15 19 

New Jersey .......................................................................... 2 8 16 5 7 

New Mexico ......................................................................... 11 18 21 16 18 

New York ............................................................................. 4 11 18 8 10 

North Carolina ...................................................................... 2 7 10 5 6 

North Dakota ........................................................................ 15 15 15 15 15 

Ohio ...................................................................................... 1 6 11 4 5 

Oklahoma ............................................................................. 11 19 20 18 20 

Oregon ................................................................................. 12 19 21 17 19 

Pennsylvania ........................................................................ 2 9 16 5 7 

Rhode Island ........................................................................ 1 4 6 3 3 

South Carolina ..................................................................... 2 7 10 5 6 

South Dakota ....................................................................... 24 15 15 15 15 

Tennessee ........................................................................... 1 3 6 2 3 

Texas ................................................................................... 8 16 20 13 15 

Utah ...................................................................................... 3 5 7 4 5 

Virginia ................................................................................. 3 12 16 9 12 

Washington .......................................................................... 7 12 15 10 11 

West Virginia ........................................................................ 2 8 14 5 6 

Wisconsin ............................................................................. 5 8 11 7 8 

Wyoming .............................................................................. 9 15 19 13 14 

The EPA notes that for some states, 

the RE generation targets developed 

using the proposed approach are less 

than those states’ reported RE 

generation amounts for 2012. We invite 

comment on whether the approach for 

quantifying the RE generation 

component of each state’s goal should 

be modified to include a floor based on 

reported 2012 RE generation in that 

state. 

This approach to quantification of a 

state’s RE generation target does not 

explicitly account for the amount of 

fossil fuel-fired generation in that state. 

Without such an accounting, the 

application of this approach could 

yield, for a given state, an increase in RE 

generation that exceeds the state’s 

reported 2012 fossil fuel-fired 

generation.155 The EPA invites comment 

on whether this approach should be 

modified so that the difference between 

a state’s RE generation target and its 

2012 level of corresponding RE 

generation does not exceed the state’s 


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156For example, for the state of Washington the 

proposed approach yields a final RE generation 

target of 17.7 TWh, representing an increase of 9.5 

TWh over Washington’s reported 2012 RE 

generation (excluding hydropower) of 8.2 TWh. By 

comparison, Washington’s 2012 reported fossil fuelfired generation was 9.4 TWh. (The 2012 reported 

RE and fossil fuel-fired generation amounts for all 

states are included in the Goal Computation TSD.) 

If the limitation described in the text were applied 

to Washington, the state’s incremental quantified 

RE generation would be limited to 9.4 TWh, with 

the result that the state’s final RE generation target 

would be 17.6 TWh instead of 17.7 TWh. 

157This analysis is based upon EIA’s AEO 2014 

Estimated Levelized Costs of Electricity for New 

Generation Sources, available at http://

www.eia.gov/forecasts/aeo/electricity_

generation.cfm. 

158Chen et al., ‘‘Weighing the Costs and Benefits 

of State Renewable Portfolio Standards: A 

Comparative Analysis of State-Level Policy Impact 

Projections,’’ Lawrence Berkeley National 

Laboratory, March 2007, available at http://

emp.lbl.gov/publications/weighing-costs-andbenefits-state-renewables-portfolio-standardscomparative-analysis-s. 

159 Galen Barbose, ‘‘Renewables Portfolio 

Standards in the United States: A Status Update,’’ 

Lawrence Berkeley National Lab, November 2013. 

Also to be published in Heeter et al., ‘‘Estimating 

the Costs and Benefits of Complying with 

Renewable Portfolio Standards: Reviewing 

Experience to Date’’ [review draft title]. 

UNPUBLISHED. National Renewable Energy 

Laboratory and Lawrence Berkeley National 

Laboratory. 

160NREL, ‘‘Renewable Electricity Futures Study’’, 

NREL/TP–6A20–52409, 2012, http://www.nrel.gov/

analysis/re_futures/. 

161 Galen Barbose, ‘‘Renewables Portfolio 

Standards in the United States: A Status Update,’’ 

Lawrence Berkeley National Laboratory, November 

2013. 

162http://emp.lbl.gov/rps, retrieved March 2014. 

The RPS compliance measure cited is inclusive of 

credit multipliers and banked RECs utilized for 

compliance, but excludes alternative compliance 

payments, borrowed RECs, deferred obligations, 

and excess compliance. This estimate does not 

represent official compliance statistics, which vary 

in methodology by state. 

163Lopez et al., NREL, ‘‘U.S. Renewable Energy 

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

2012). 

reported 2012 fossil fuel-fired 

generation.156

We note that with the exception of 

hydropower, the RE generation levels 

represent total amounts of RE 

generation, rather than incremental 

amounts above a particular baseline 

level. As a result, this RE generation can 

be supplied by any RE capacity 

regardless of its date of installation. This 

approach is therefore focused on 

quantifying the fulfillment of each 

state’s potential for the deployment of 

RE as part of BSER using a methodology 

that does not require discriminating 

between RE capacity that was installed 

before or after any given date. Under 

this approach, states in a given region 

where a higher proportion of total 

generation has already been achieved 

from renewable resources are assumed 

to have less opportunity for deployment 

of additional renewable generation as 

part of the BSER framework informing 

state goals, in comparison to states in 

that region where the proportion of total 

generation achieved from renewable 

resources to date has been lower. That 

being said, the assumptions of RE 

generation used to develop the state 

goals do not impose any specific RE 

generation requirements on any state; 

they are only used to inform the 

quantification of state goals to which 

states may respond with whatever 

emission reduction measures are 

preferred. 

With regard to hydropower, we seek 

comment regarding whether to include 

2012 hydropower generation from each 

state in that state’s ‘‘best practices’’ RE 

quantified under this approach, and 

whether and how the EPA should 

consider year-to-year variability in 

hydropower generation if such 

generation is included in the RE targets 

quantified as part of BSER. Chapter 4 of 

the GHG Abatement Measures TSD 

presents state RE targets both with and 

without the inclusion of each state’s 

2012 hydropower generation. 

2. Cost of CO2 Emission Reductions 

From RE Generation 

The EPA believes that RE generation 

at the levels represented in the best 

practices scenario can be achieved at 

reasonable costs. According to an EPA 

analysis based on EIA levelized costs, 

the cost to reduce emissions through RE 

ranges from $10 to $40 per metric ton 

of CO2.157 Analysis of RE development 

in response to state RPS policies also 

finds historical and projected costs of 

RPS-driven RE deployment to be 

modest. One comparative analysis that 

‘‘synthesize[d] and analyze[d] the 

results and methodologies of 28 distinct 

state or utility-level RPS cost impact 

analyses’’ projected the median change 

in retail electricity price to be $0.0004 

per kilowatt-hour (a 0.7 percent 

increase), the median monthly bill 

impact to be between $0.13 and $0.82, 

and the median CO2 reduction cost to be 

$3 per metric ton.158 This finding has 

been confirmed with more recent RPS 

cost data, including a report that 

determined 2010–2012 retail electricity 

price impacts due to state RPS policies 

to be less than two percent, with only 

two states experiencing price impacts of 

greater than three percent.159

Additionally, the National Renewable 

Energy Laboratory has projected low 

incremental costs for a range of 

scenarios reflecting significant increases 

in RE penetration, including scenarios 

that increase RE penetration to a range 

of 30 to 40 percent of national 

generation, levels higher than those 

projected in our best practices 

scenario.160

While RPS requirements will 

continue to grow over time, the EPA 

does not expect this anticipated 

expansion to fall outside the historical 

norms of deployment or to create 

unusual pressure for cost increases. Full 

compliance with current RPS goals 

through 2035 would require 

approximately 4 to 4.5 GW of new 

renewable capacity per year. Average 

deployment of RPS-supported 

renewable capacity from 2007 to 2012 

exceeded 6 GW per year.161 In addition, 

recent improvements in RPS 

compliance rates indicate to the EPA the 

reasonableness of current RPS growth 

trajectories. Weighted average 

compliance rates among all states have 

improved in each of the past three 

reported years (2008–2011) from 92.1 

percent to 95.2 percent despite a 40 

percent increase in RPS obligations 

during this period.162

We invite comment on this approach 

to treatment of renewable generating 

capacity as a basis for the best system 

of emission reduction adequately 

demonstrated and for quantification of 

state goals. 

3. Alternative Approach to 

Quantification of RE Generation 

Additionally, the EPA is soliciting 

comment on an alternative approach to 

quantification of renewable generation 

to support the BSER. Unlike the 

proposed RE scenario described above 

that relies on a regional application of 

state RPS commitments, the alternative 

methodology relies on a state-by-state 

assessment of RE technical and market 

potential. The alternative approach is 

based on two sources of information: A 

metric representing the degree to which 

the technical potential of states to 

develop RE generation has already been 

realized, and IPM modeling of RE 

deployment at the state level under a 

scenario that reflects a reduced cost of 

building new renewable generating 

capacity. 

The metric measuring realization of 

RE technical potential in a state 

compares each state’s existing 

renewable generation by technology 

type with the technical potential for that 

technology in that state as assessed by 

the National Renewable Energy 

Laboratory (NREL).163 This comparison 

yields, for each state and for each RE 

technology, a proportion of renewable 

generation technical potential that has 

been achieved and can be represented as 

an RE development rate. For example, if 


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164Additional detail regarding this modeling and 

approach is provided in the Alternative RE 

Approach TSD. 

165The Alternative RE Approach TSD presents 

the quantification of hydropower generation under 

the alternative approach, as well as the resulting 

state RE targets both with and without hydropower 

generation included. 

a given state has 500 MWh of solar 

generation in 2012 while NREL assesses 

that state’s solar generation technical 

potential at 5,000 MWh/year, then that 

state’s solar RE development rate would 

be ten percent. The EPA then considers 

the range of RE development rates 

across states in order to define a 

benchmark RE development rate for 

each technology. 

While a benchmark RE development 

rate offers a useful metric to quantify the 

proportion of RE generation that would 

bring all states up to a designated 

proportion of RE generation that has 

been achieved in practice by certain 

states to date, such a metric does not 

explicitly take into account the cost that 

would be faced to reach the benchmark 

RE development rate in each state. In 

order to take this cost into account, for 

this alternative approach the EPA has 

paired the benchmark RE development 

rates described above with IPM 

modeling of RE deployment at the state 

level, based on a scenario reflecting a 

reduced cost of building new renewable 

generating capacity. The cost reduction 

for new RE generating capacity is 

intended to represent the avoided cost 

of other actions that could be taken 

instead to reduce CO2 emissions from 

the power sector. In the Alternative RE 

Approach TSD, available in the docket, 

we show the RE deployment levels 

modeled using a cost reduction of up to 

$30 per MWh, a level that is consistent 

with the cost range of $10 to $40 per 

metric ton of avoided CO2 emissions 

estimated for the proposed RE scenario 

described above.164

Under this alternative RE approach, 

the EPA would quantify RE generation 

for each technology in each state as the 

lesser of (1) that technology’s 

benchmark rate multiplied by the 

technology’s in-state technical potential, 

or (2) the IPM-modeled market potential 

for that specific technology. For 

example, if the benchmark RE 

development rate for solar generation is 

determined to be 12 percent, and the 

hypothetical state described above has a 

solar generation technical potential of 

5,000 MWh/year, then the benchmark 

RE development level of generation for 

that state would be 600 MWh/year. If 

the IPM-modeled market potential for 

solar generation in that state is 750 

MWh/year, then this approach would 

quantify solar generation for that state as 

the benchmark RE development level 

(600 MWh/year) because it is the lesser 

amount of those two measures. 

Having quantified an amount of RE 

generation from each RE technology in 

each state, the EPA would then 

determine for each state a total level of 

RE generation that equals the sum of the 

generation quantified for each of the 

assessed RE technologies in that state. If 

the EPA were to adopt this alternative 

approach for quantifying RE in BSER, 

these total levels of RE generation for 

each state would be incorporated in 

state goals in place of the RE generation 

levels quantified using the proposed 

approach described above. Further 

methodological detail and state-level RE 

targets for this alternative approach are 

provided in the Alternative RE 

Approach TSD in the docket. 

We invite comment on this alternative 

approach to quantification of RE 

generation to support the BSER. We 

note that the three specific requests for 

comment made above with respect to 

the proposed quantification approach— 

addressing, first, the possibility of a 

floor based on 2012 RE generation, 

second, the possibility of a limitation 

based on 2012 fossil fuel-fired 

generation and, third, the treatment of 

hydropower generation—apply to this 

alternative approach as well.165

Finally, the EPA notes that the 

alternative RE approach described above 

is one of a number of possible 

methodologies for using technical and 

economic renewable energy potential to 

quantify RE generation for purposes of 

state goals. The EPA invites comment 

on other possible techno-economic 

approaches. For example, a conceptual 

framework for another techno-economic 

approach is provided in the Alternative 

RE Approach TSD. 

b. New and Preserved Nuclear Capacity 

Nuclear generating capacity facilitates 

CO2 emission reductions at fossil fuelfired EGUs by providing carbon-free 

generation that can replace generation at 

those EGUs. Because of their relatively 

low variable operating costs, nuclear 

EGUs that are available to operate 

typically are dispatched before fossil 

fuel-fired EGUs. Increasing the amount 

of nuclear capacity relative to the 

amount that would otherwise be 

available to operate is therefore a 

technically viable approach to support 

reducing CO2 emissions from affected 

fossil fuel-fired EGUs. 

1. Proposed Quantification of Nuclear 

Generation 

One way to increase the amount of 

available nuclear capacity is to build 

new nuclear EGUs. However, in 

addition to having low variable 

operating costs, nuclear generating 

capacity is also relatively expensive to 

build compared to other types of 

generating capacity, and little new 

nuclear capacity has been constructed 

in the U.S. in recent years; instead, most 

recent generating capacity additions 

have consisted of NGCC or renewable 

capacity. Nevertheless, five nuclear 

EGUs at three plants are currently under 

construction: Watts Bar 2 in Tennessee, 

Vogtle 3–4 in Georgia, and Summer 2– 

3 in South Carolina. The EPA believes 

that since the decisions to construct 

these units were made prior to this 

proposal, it is reasonable to view the 

incremental cost associated with the 

CO2 emission reductions available from 

completion of these units as zero for 

purposes of setting states’ CO2 reduction 

goals (although the EPA acknowledges 

that the planning for those units likely 

included consideration of the possibility 

of future regulation of CO2 emissions 

from EGUs). Completion of these units 

therefore represents an opportunity to 

reduce CO2 emissions from affected 

fossil fuel-fired EGUs at a very 

reasonable cost. For this reason, we are 

proposing that the emission reductions 

achievable at affected sources based on 

the generation provided at the identified 

nuclear units currently under 

construction should be factored into the 

state goals for the respective states 

where these new units are located. 

However, the EPA also realizes that 

reflecting completion of these units in 

the goals has a significant impact on the 

calculated goals for the states in which 

these units are located. If one or more 

of the units were not completed as 

projected, that could have a significant 

impact on the state’s ability to meet the 

goal. We therefore take comment on 

whether it is appropriate to reflect 

completion of these units in the state 

goals and on alternative ways of 

considering these units when setting 

state goals. 

Another way to increase the amount 

of available nuclear capacity is to 

preserve existing nuclear EGUs that 

might otherwise be retired. The EPA is 

aware of six nuclear EGUs at five plants 

that have retired or whose retirements 

have been announced since 2012: San 

Onofre Units 2–3 in California, Crystal 

River 3 in Florida, Kewaunee in 

Wisconsin, Vermont Yankee in 

Vermont, and Oyster Creek in New 

Jersey. While each retirement decision 


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166 Jeffrey Jones and Michael Leff, EIA, 

‘‘Implications of accelerated power plant 

retirements,’’ (April 2014). 167Assuming replacement power for at-risk 

nuclear capacity is sourced from new NGCC 

capacity at 800 lbs/MWh or the power system at 

1127 lbs CO2/MWh (average 2020 power sector 

emissions intensity as projected in the EPA’s IPM 

Base Case). 168 ‘‘Nuclear * * * The Middle Age Dilemma?’’ 

Eggers, et al., Credit Suisse, February 2013. 

169A state’s historical nuclear fleet is defined as 

all units in commercial operation as of May 2014 

with no current plans to retire. 

170Electricity end-users and electricity end-use 

referred to throughout this subsection include the 

residential, commercial and industrial sectors. 

171Energy Information Administration Form 861, 

2012, available at http://www.eia.gov/electricity/ 

data/eia861/. 

172See, e.g., Electric Power Research Institute, 

U.S. Energy Efficiency Potential Through 2035 

(Final Report, April 2014); Wang, Yu and Marilyn 

A. Brown, Policy Drivers for Improving Electricity 

End-Use Efficiency in the U.S.: An EconomicEngineering Analysis (Energy Efficiency, 2014). 

173 Innovation, Electricity, Efficiency (an Institute 

of the Edison Foundation), Summary of CustomerFunded Electric Efficiency Savings, Expenditures, 

and Budgets (2011–2012) (March 2013), available at 

http://www.edisonfoundation.net/iei/ourwork/ 

Pages/issuebriefs.aspx. 

is based on the unique circumstances of 

that individual unit, the EPA recognizes 

that a host of factors—increasing fixed 

operation and maintenance costs, 

relatively low wholesale electricity 

prices, and additional capital 

investment associated with ensuring 

plant security and emergency 

preparedness—have altered the outlook 

for the U.S. nuclear fleet in recent years. 

Reflecting similar concern for these 

challenges, EIA in its most recent 

Annual Energy Outlook has projected an 

additional 5.7 GW of capacity 

reductions to the nuclear fleet. EIA 

describes the projected capacity 

reductions—which are not tied to the 

projected retirement of any specific 

unit—as necessary to recognize the 

‘‘continued economic challenges’’ faced 

by the higher-cost nuclear units.166

Likewise, without making any judgment 

about the likelihood that any individual 

EGU will retire, we view this 5.7 GW, 

which comprises an approximately six 

percent share of nuclear capacity, as a 

reasonable proxy for the amount of 

nuclear capacity at risk of retirement. 

2. Cost of CO2 Emission Reductions 

From Nuclear Generation 

We have determined that, based on 

available information regarding the cost 

and performance of the nuclear fleet, 

preserving the operation of at-risk 

nuclear capacity would likely be 

capable of achieving CO2 reductions 

from affected EGUs at a reasonable cost. 

For example, retaining the estimated six 

percent of nuclear capacity that is at risk 

for retirement could support avoiding 

200 to 300 million metric tons of CO2

over an initial compliance phase-in 

period of ten years.167 According to a 

recent report, nuclear units may be 

experiencing up to a $6/MWh shortfall 

in covering their operating costs with 

electricity sales.168 Assuming that such 

a revenue shortfall is representative of 

the incentive to retire at-risk nuclear 

capacity, one can estimate the value of 

offsetting the revenue loss at these atrisk nuclear units to be approximately 

$12 to $17 per metric ton of CO2. The 

EPA views this cost as reasonable. We 

therefore propose that the emission 

reductions supported by retaining in 

operation six percent of each state’s 

historical nuclear capacity should be 

factored into the state goals for the 

respective states.169

For purposes of goal computation, 

generation from under-construction and 

preserved nuclear capacity is based on 

an estimated 90 percent average 

utilization rate for U.S. nuclear units, 

consistent with long-term average 

annual utilization rates observed across 

the nuclear fleet. The methodology for 

taking this generation into account for 

purposes of setting state emission rate 

goals is described below in Section VII 

on state goals and in the Goal 

Computation TSD. 

We invite comment on all aspects of 

the approach discussed above. In 

addition, we specifically request 

comment on whether we should include 

in the state goals an estimated amount 

of additional nuclear capacity whose 

construction is sufficiently likely to 

merit evaluation for potential inclusion 

in the goal-setting computation. If so, 

how should we do so—for example, 

according to EGU owners’ 

announcements, the issuance of 

permits, projections of new construction 

by the EPA or another government 

agency, or commercial projections? 

What specific data sources should we 

consider for those permits or 

projections? 

4. Building Block 4—Demand-Side 

Energy Efficiency 

The fourth element of the foundation 

for the EPA’s BSER determination for 

reducing CO2 emissions at affected 

fossil fuel-fired EGUs also supports 

reduced mass emissions at all affected 

EGUs, and entails an analysis of the 

extent to which generation reductions at 

the affected EGUs can be supported by 

reducing the demand for generation at 

those EGUs through measures that 

reduce the overall quantity of generation 

demanded by end-users.170

a. Benefits of Demand-Side Energy 

Efficiency 

Reducing demand for generation at 

affected EGUs through policies to 

improve demand-side energy efficiency 

is a proven basis for reducing CO2

emissions at those EGUs. Every state has 

established demand-side energy 

efficiency policies, and many 

stakeholders emphasized the success of 

these policies in reducing electricity 

consumption by large amounts. For 

example, data reported to the U.S. 

Energy Information Administration 

(EIA) show that in 2012 California and 

Minnesota avoided 12.5 percent and 

13.1 percent of their electricity demand, 

respectively, through their demand-side 

efficiency programs.171 Additionally, 

multiple studies have found that 

significant improvements in end-use 

energy efficiency can be realized at less 

cost than the savings from avoided 

power system costs.172 Increased 

investment in demand-side energy 

efficiency is being supported by efforts 

at the federal, state, and local levels of 

government as well as corporate efforts. 

Many stakeholders urged the inclusion 

of demand-side energy efficiency 

policies as compliance options under 

the CAA section 111(d) guidelines. 

By reducing electricity consumption, 

energy efficiency avoids greenhouse gas 

emissions associated with electricity 

generation. Because fossil fuel-fired 

EGUs typically have higher variable 

costs than other EGUs (such as nuclear 

and renewable EGUs), their generation 

is typically the first to be replaced when 

demand is reduced. Consequently, 

reductions in the utilization of fossil 

fuel-fired EGUs can be supported by 

reducing electricity consumption and, 

by the same token, reductions in 

electricity consumption avoid the CO2

emissions associated with the avoided 

generation. In this manner, in 2011, 

state demand-side energy efficiency 

programs are estimated to have reduced 

CO2 emissions by 75 million metric 

tons.173 And when integrated into a 

comprehensive approach for addressing 

CO2 emissions, demand-side energy 

efficiency improvements offer even 

more potential to improve the carbon 

profile of the electricity supply system. 

For example, if incentives exist to shift 

generation to lower carbon-intensity 

EGUs, and those EGUs are fully utilized, 

reducing demand can support further 

reductions in carbon intensity. This 

potential effect reinforces the 

appropriateness of incorporating 

demand-side efficiency improvements 

into a comprehensive approach to 

address power sector CO2 emissions. In 

addition, by supporting reductions in 

fossil fuel usage at EGUs, demand-side 


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174Energy efficiency programs are driven by a 

variety of state policies including energy efficiency 

resource standards, requirements to acquire all costeffective energy efficiency, integrated resource 

planning requirements, and demand-side 

management plans and budgets. Funding for energy 

efficiency programs is provided through a variety of 

mechanisms as well, including per kilowatt-hour 

surcharges and proceeds from forward capacity 

market and emission allowance auctions. The 

programs are implemented by a range of entities 

including investor-owned, municipal, and 

cooperative electric utilities, state agencies, and 

designated third-party administrators. All end-use 

sectors (residential, commercial, and industrial) are 

targeted by energy efficiency programs and 

numerous strategies are employed, including 

targeted rebates for high-efficiency appliances; 

energy audits with recommendations for costeffective, energy-saving upgrades; and processes to 

certify energy efficiency service providers. 

175See the appendix to the State Plan 

Considerations TSD for descriptions of the full 

array of demand-side energy efficiency policies 

currently employed by states. 

176EERS establish specific, long-term targets for 

energy savings that utilities or non-utility program 

administrators must meet through customer energy 

efficiency programs. EERS, as well as requirements 

that utilities acquire all cost-effective energy 

efficiency, have been the most impactful state 

energy efficiency strategies in recent years. 

177The historical data used are reported to the 

Energy Information Administration through Form 

EIA–861. The analysis and summary of state energy 

efficiency policies is from the American Council for 

an Energy-Efficient Economy (ACEEE), State EERS 

Activity Policy Brief (February 24, 2014). See the 

Greenhouse Gas Abatement Measures TSD for more 

information. 

178E.g., energy efficiency programs operated by 

municipal and cooperative utilities may report their 

program results to their Boards of Directors rather 

than to a state utility commission. 

179See the EM&V section of the State Plan TSD 

for more information on EE program evaluation. 

180This incremental savings rate and all others 

discussed in this subsection represent net, rather 

than gross, energy savings. Gross savings are the 

changes in energy use (MWh) that result directly 

from program-related actions taken by program 

participants, regardless of why they participated in 

a program. Net savings refer to the changes in 

energy use that are directly attributable to a 

particular energy efficiency program after 

accounting for free-ridership, spillover, and other 

factors. 

181 2012 is the most recent year for energy 

efficiency program incremental savings data 

reported using EIA Form 861. 

182See the Greenhouse Gas Abatement Measures 

TSD for more information. 

energy efficiency supports not only 

reduced CO2 emissions and carbon 

intensity of the power sector, but also 

reduced criteria pollutant emissions, 

cooling water intake and discharge, and 

solid waste production associated with 

fossil fuel combustion. By reducing 

electricity usage significantly, energy 

efficiency also commonly reduces the 

bills of electricity customers. 

b. ‘‘Best Practices’’ for Demand-Side 

Energy Efficiency 

To estimate the potential CO2

reductions at affected EGUs that could 

be supported by implementation of 

demand-side energy efficiency policies 

as a part of state goals, the EPA 

developed a ‘‘best practices’’ demandside energy efficiency scenario. This 

scenario provides an estimate of the 

potential for sources and states to 

implement policies that increase 

investment in demand-side energy 

efficiency technologies and practices at 

reasonable costs. It does not represent 

an EPA forecast of business-as-usual 

impacts of state energy efficiency 

policies or an EPA estimate of the full 

potential of end-use energy efficiency 

available to the power system, but rather 

represents a feasible policy scenario 

showing the reductions in fossil fuelfired electricity generation resulting 

from accelerated use of energy 

efficiency policies in all states 

consistent with a level of performance 

that has already been achieved or 

required by policies (e.g., energy 

efficiency resource standards) of the 

leading states. The data and 

methodology used to develop the best 

practices scenario are summarized 

below. 

We have not assumed any particular 

type of demand-side energy efficiency 

policy. States with leading energy 

efficiency performance have employed a 

variety of strategies that are 

implemented by a range of entities 

including investor-owned, municipal 

and cooperative electric utilities as well 

as state agencies and third-party 

administrators. These include energy 

efficiency programs,174 building energy 

codes, state appliance standards (for 

appliances without federal standards), 

tax credits, and benchmarking 

requirements for building energy use.175

Energy efficiency policies are designed 

to accelerate the deployment of 

demand-side energy efficiency 

technologies, practices, and measures by 

addressing market barriers and market 

failures that limit their adoption. Some 

states have adopted energy efficiency 

resource standards 176 (EERS) to drive 

investment in energy efficiency 

programs; some have relied on other 

strategies; most states are using multiple 

policy approaches. Based on historical 

data on energy efficiency program 

savings and analysis of the requirements 

of existing state energy efficiency 

policies, twelve leading states have 

either achieved—or have established 

requirements that will lead them to 

achieve—annual incremental savings 

rates of at least 1.5 percent of the 

electricity demand that would otherwise 

have occurred.177 The 1.5 percent 

savings rate is inclusive of, not 

additional to, existing state energy 

efficiency requirements. These savings 

levels are realized exclusively through 

the adoption and implementation of 

energy efficiency programs. The energy 

savings data underpinning these 

analyses are derived from energy 

efficiency program reports required by 

state public utility commissions and 

other entities with a similar oversight 

role.178 These state commissions define 

and oversee the analysis and reporting 

requirements for energy efficiency 

programs as part of their role of 

overseeing rates for utility customers in 

their states. One typical requirement is 

the application of recognized 

evaluation, measurement, and 

validation (EM&V) protocols that 

specify industry-preferred approaches 

and methodologies for estimating 

savings from efficiency programs.179

While EM&V data reflect documented 

electricity savings from energy 

efficiency programs, they typically do 

not account for potential electricity 

savings available from additional stateimplemented policies for which EM&V 

protocols are less consistently required 

or applied, such as building energy 

codes. Thus, we consider the 1.5 

percent annual incremental savings 180

rate to be a reasonable estimate of the 

energy efficiency policy performance 

that is already achieved or required by 

leading states and that can be achieved 

at reasonable costs by all states given 

adequate time. If we were to capture the 

potential for additional policies, such as 

the adoption and enforcement of state or 

local building energy codes, to 

contribute additional reductions in 

electricity demand beyond those 

resulting from energy efficiency 

programs, we could reasonably increase 

the targeted annual incremental savings 

rate beyond 1.5 percent. 

For states where EE program 

experience is more limited, reaching a 

best-practices level of performance 

requires undertaking a set of activities 

that takes some time to plan, 

implement, and evaluate. For the best 

practices scenario, we have therefore 

estimated that each state’s annual 

incremental savings rate increases from 

its 2012 annual saving rate 181 to a rate 

of 1.5 percent over a period of years 

starting in 2017. (Thus, the goal for each 

state differs to reflect the assumption 

that in a state already close to a 1.5 

percent annual incremental savings rate, 

energy efficiency programs can be 

expanded to reach that rate sooner than 

in a state that is further from that rate.) 

The pace at which states are estimated 

to increase their savings rate level is 0.2 

percent per year. This rate is consistent 

with past performance and future 

requirements of leading states.182 For 

states already at or above the 1.5 percent 


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183For example, a state with a reported savings 

rate of 0.5% in 2012 is assumed to realize a 2017 

savings rate of 0.5% and their savings rates for 

2018, 2019, 2020, 2021 and 2022 are calculated to 

be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively. 

By this method, all states have reached the 1.5% 

target rate by 2017 at the earliest and by 2025 at 

the latest. 

184See the Greenhouse Gas Abatement Measures 

TSD for more information. 

annual incremental savings rate (based 

on 2012 reported data), we estimate that 

they would realize a 1.5 percent rate in 

2017 and maintain that rate through 

2029. For all states we assume the initial 

savings rate (the lower of their 2012 

value or 1.5 percent) is realized in 2017 

and increases each year by 0.2 percent 

until the target rate of 1.5 percent is 

achieved 183 and is then maintained at 

that level through 2029. The savings 

from energy efficiency programs are 

cumulative, meaning that, in simplified 

terms, a state in which a sustained 

program is implemented with a 1.5 

percent annual incremental savings rate 

could expect cumulative annual savings 

of approximately 1.5 percent after the 

first year, 3.0 percent after the second 

year, 4.5 percent after the third year, 

and so on. Savings from the first year 

would drop off at the end of the average 

life of the energy efficiency program 

portfolio (typically about ten years). 

Accordingly, we have projected the 

cumulative annual savings for each state 

that would be achieved for the period 

2020 to 2029 based on the state’s 

reaching and then sustaining the best 

practices annual incremental savings 

rate through 2029. These values, for 

each state and for each year (2020– 

2029), are used in the procedure for 

computing the state goals described in 

Section VII.C below. 

As discussed in Section VII.E below, 

the EPA is also taking comment on a 

less stringent alternative for setting state 

goals. Under this alternative, the 

demand-side energy efficiency 

requirement uses 1.0 percent (rather 

than 1.5 percent) annual incremental 

savings as representative of the bestpractices level of performance. In 

addition, the pace at which incremental 

savings levels are increased from their 

historical levels is relaxed slightly to 

0.15 percent per year (rather than 0.2 

percent). The 1.0 percent rate of savings 

is a level of performance that has been 

achieved—or that established state 

requirements will cause to be 

achieved—by 20 states.184 As is done 

with the more stringent goal-setting 

approach for energy efficiency, the 

cumulative percentages for each state 

are derived and multiplied by the state’s 

2012 historical electricity sales as 

reflected in the EIA detailed state data, 

in this case for the period from 2020 to 

2024. 

The state-specific cumulative annual 

electricity saving data inputs for both 

the proposed approach and the less 

stringent alternative are discussed in the 

Greenhouse Gas Abatement Measures 

TSD and summarized in Table 7. 

TABLE 7—DEMAND-SIDE ENERGY EFFICIENCY STATE GOAL DEVELOPMENT: CUMULATIVE ANNUAL ELECTRICITY SAVINGS

(PERCENTAGE OF ANNUAL SALES) RESULTING FROM BEST PRACTICES SCENARIO 185

State 

1.5% Savings target scenario 1.0% Savings target scenario 

2020 2029 2020 2024 

Alabama ........................................................................................................... 1.4 9.5 1.1 3.9 

Alaska .............................................................................................................. 1.2 9.5 0.9 3.7 

Arizona ............................................................................................................. 5.2 11.4 3.5 6.0 

Arkansas .......................................................................................................... 1.5 9.7 1.2 4.1 

California .......................................................................................................... 5.0 11.6 3.6 6.1 

Colorado .......................................................................................................... 3.9 11.0 3.3 5.9 

Connecticut ...................................................................................................... 4.7 11.9 3.6 6.3 

Delaware .......................................................................................................... 1.1 9.5 0.9 3.6 

Florida .............................................................................................................. 2.0 10.0 1.8 4.7 

Georgia ............................................................................................................ 1.8 9.8 1.5 4.4 

Hawaii .............................................................................................................. 1.3 9.5 1.0 3.8 

Idaho ................................................................................................................ 3.8 11.1 3.5 5.9 

Illinois ............................................................................................................... 4.4 11.6 3.5 6.2 

Indiana ............................................................................................................. 3.2 11.1 2.9 5.7 

Iowa ................................................................................................................. 4.7 11.7 3.6 6.0 

Kansas ............................................................................................................. 1.2 9.5 0.9 3.7 

Kentucky .......................................................................................................... 1.9 10.0 1.6 4.6 

Louisiana .......................................................................................................... 1.1 9.3 0.9 3.6 

Maine ............................................................................................................... 5.4 12.1 3.6 6.3 

Maryland .......................................................................................................... 4.2 11.5 3.5 6.1 

Massachusetts ................................................................................................. 4.4 11.8 3.6 6.2 

Michigan ........................................................................................................... 4.6 11.8 3.6 6.2 

Minnesota ........................................................................................................ 4.8 11.7 3.6 6.2 

Mississippi ........................................................................................................ 1.4 9.6 1.1 3.9 

Missouri ............................................................................................................ 1.6 9.9 1.3 4.2 

Montana ........................................................................................................... 3.4 10.9 3.0 5.7 

Nebraska .......................................................................................................... 2.2 10.4 1.9 4.9 

Nevada ............................................................................................................. 3.0 10.7 2.7 5.5 

New Hampshire ............................................................................................... 2.8 11.0 2.6 5.5 

New Jersey ...................................................................................................... 1.3 9.6 1.0 3.7

New Mexico ..................................................................................................... 3.1 10.6 2.8 5.5

New York ......................................................................................................... 4.4 11.8 3.5 6.2 

North Carolina .................................................................................................. 2.4 10.3 2.1 5.0 

North Dakota .................................................................................................... 1.4 9.7 1.1 4.0

Ohio ................................................................................................................. 4.2 11.6 3.5 6.1 

Oklahoma ......................................................................................................... 1.9 10.0 1.6 4.5 

Oregon ............................................................................................................. 4.7 11.4 3.6 6.1 

Pennsylvania .................................................................................................... 4.7 11.7 3.6 6.2 


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185 Vermont and the District of Columbia are 

excluded from this table because we are not 

proposing goals for those jurisdictions. 

186Some states do include a valuation of CO2

benefits as part of their evaluations of cost 

effectiveness. 

187E.g., Electric Power Research Institute, U.S. 

Energy Efficiency Potential Through 2035 (Final 

Report, April 2014); Northwest Power and 

Conservation Council, Sixth Northwest 

Conservation and Electric Power Plan (Feb. 2010), 

available at http://www.nwcouncil.org/energy/ 

powerplan/6/plan/. 

188As described below and in the Goal 

Computation TSD, in the case of a state that is a 

net importer of electricity, the proposed goal 

computation procedure includes an adjustment to 

account for the possibility that some of the 

generation and emissions avoided due to the state’s 

demand-side energy efficiency programs may occur 

at EGUs in other states. Given the extremely low 

cost of CO2 emission reductions achievable through 

demand-side energy efficiency programs, 

implementation of such programs is likely to reduce 

CO2 emissions at reasonable cost even for a state 

whose own affected EGUs achieve only part of the 

CO2 emission reduction benefit from the state’s 

demand-side energy efficiency efforts. 

189American Council for an Energy-Efficient 

Economy (ACEEE), The Best Value for America’s 

Energy Dollar: A National Review of the Cost of 

TABLE 7—DEMAND-SIDE ENERGY EFFICIENCY STATE GOAL DEVELOPMENT: CUMULATIVE ANNUAL ELECTRICITY SAVINGS

(PERCENTAGE OF ANNUAL SALES) RESULTING FROM BEST PRACTICES SCENARIO 185—Continued 

State 

1.5% Savings target scenario 1.0% Savings target scenario 

2020 2029 2020 2024 

Rhode Island .................................................................................................... 3.9 11.6 3.4 6.1 

South Carolina ................................................................................................. 2.3 10.2 2.0 4.9

South Dakota ................................................................................................... 1.6 9.9 1.3 4.2 

Tennessee ....................................................................................................... 2.2 10.3 1.9 4.9 

Texas ............................................................................................................... 1.8 9.9 1.5 4.4 

Utah ................................................................................................................. 3.6 11.0 3.2 5.8 

Virginia ............................................................................................................. 1.2 9.3 1.0 3.7 

Washington ...................................................................................................... 4.2 11.3 3.5 6.0 

West Virginia .................................................................................................... 1.8 10.1 1.5 4.4 

Wisconsin ......................................................................................................... 4.7 11.8 3.6 6.2 

Wyoming .......................................................................................................... 1.6 9.7 1.3 4.2 

c. Costs of Demand-Side Energy 

Efficiency 

The EPA expects implementation of 

demand-side energy efficiency policies 

as reflected in the best practices 

scenario to be achievable at reasonable 

costs. The EPA finds support for the 

reasonableness of the costs of this 

building block from two perspectives. 

First, the specific savings levels 

represented by this building block were 

developed based upon the experience 

and success of states in developing and 

implementing energy efficiency policies 

that they undertake primarily for the 

purpose of providing economic benefits 

to electricity consumers in their state. 

Secondly, even with notably 

conservative assumptions about the 

costs of achieving the levels of 

electricity savings associated with this 

building block, the EPA’s analysis of the 

power sector indicates that the costs are 

reasonable. 

The processes by which states 

develop funding for energy efficiency 

programs typically require the 

application of cost-effectiveness tests to 

ensure that adopted program portfolios 

lead to lower costs than the use of 

generation sources that would otherwise 

be required to meet the associated 

electricity service demands. Indeed, a 

major reason for the widespread 

presence and rapid growth of demandside energy efficiency programs is the 

strong evidence of the reasonableness of 

their costs even before the additional 

benefit of CO2 reductions is 

considered.186 Independent studies 

have found that end-users’ needs for 

energy-dependent services (e.g., heating, 

cooling, lighting, motor output, and 

information and entertainment services) 

frequently can be satisfied at lower cost 

by improving the efficiency of 

electricity consumption rather than by 

increasing the supply of electricity.187

These factors indicate that the cost of 

CO2 reductions achieved through 

implementation of demand-side energy 

efficiency at the levels reflected in the 

best practices scenario are likely to be 

very reasonable, typically resulting in 

reductions in average electricity bills 

across all end-use sectors.188 Because 

demand-side energy efficiency costs are 

incurred at the time of investment, 

while the cost savings (from lower 

electricity usage) are realized over the 

life of these investments (typically about 

10 years), bill reductions are greater in 

later years, but provide substantial 

payback over the investment period. 

Another approach to evaluating the 

reasonableness of the costs associated 

with this building block is to compare 

the demand-side energy efficiency costs 

to the avoided power system costs as 

represented within the EPA’s modeling 

of the power sector. The costs associated 

with the best practices scenario were 

estimated based upon a synthesis of 

data and analysis of the factors that 

impact energy efficiency program costs 

as calculated using an engineeringbased, bottom-up approach that is 

standard for state and utility analysis of 

these policies. These factors include the 

average energy efficiency program costs 

per unit of first-year energy savings 

($/MWh), the ratio of program to 

participant costs, and the lifetimes of 

energy efficiency measures across the 

full portfolio of programs. In addition, 

the EPA has included a cost escalation 

factor to represent the possibility of 

increased costs associated with higher 

levels of incremental energy savings 

rates and the national scope of the best 

practices scenario. The EPA has taken a 

conservative approach to each of these 

factors, selecting values that are at the 

higher-cost end of reasonable ranges of 

estimated values. The combination of 

these factors is reflected in the value the 

EPA has derived for the levelized cost 

per MWh of saved energy. This value 

includes both the program costs paid by 

utilities for implementing energy 

efficiency programs and the amounts 

that program participants pay for their 

own energy efficiency improvements 

beyond the program costs. These costs 

are levelized across the measure 

lifetimes of a full portfolio of energy 

efficiency programs. This analysis 

provides a levelized cost of saved 

energy (LCOSE) range of $85/MWh to 

$90/MWh ($2011) over the 2020 to 2030 

period. This range of LCOSE is notably 

conservative (leading to higher costs) in 

comparison with most utility and state 

analysis. For example, a 2014 analysis 

by the American Council for an EnergyEfficient Economy (ACEEE) surveyed 

program and participant cost results 

across seven states and found a 

comparable LCOSE value of $54/MWh 

(2011$).189


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Utility Energy Efficiency Programs (Report No. 

U1402, March 2014). 

To estimate the reductions in power 

system costs and CO2 emissions 

associated with the best-practices level 

of demand-side energy efficiency 

described above, the EPA analyzed a 

scenario incorporating the resulting 

reduction in electricity demand and 

compared the results with the businessas-usual scenario. Both analyses were 

conducted using the Integrated Planning 

Model (IPM) described previously. 

Combining the resulting power system 

cost reductions with the energy 

efficiency cost estimates associated with 

the best practices scenario, the EPA 

derived net cost impacts for 2020, 2025, 

and 2030. Dividing these net cost 

impacts by the associated CO2

reductions for each year, the EPA found 

that the average cost of the CO2

reductions achieved ranged from $16 to 

$24 per metric ton of CO2. The EPA 

views these estimated costs as 

reasonable. Together with the history of 

demonstrated successful state 

implementation of demand-side energy 

efficiency programs at reasonable costs 

discussed above, this analysis supports 

the reasonableness of the level of 

demand-side energy efficiency 

represented by the best practices 

scenario and, by extension, the 

reasonableness of the emission 

reductions at affected EGUs that can be 

achieved consistent with achievement 

of that level of demand-side energy 

efficiency. 

Further details regarding the data and 

methodology used to evaluate the 

potential for demand-side energy 

efficiency programs to substitute for 

generation at affected EGUs and thereby 

facilitate reductions of power sector CO2

emissions at reasonable costs are 

provided in the Greenhouse Gas 

Abatement Measures TSD. We invite 

comment on all aspects of our data and 

methodology as discussed above and in 

the TSD, as well as on the level of 

reductions we propose to define as best 

practices suitable for representation 

consistent with the best system of 

emission reduction and the level 

reflected in the less stringent scenario. 

We also specifically invite comment on 

several issues: (1) Increasing the annual 

incremental savings rate to 2.0 percent 

and the pace of improvement to 0.25 

percent per year to reflect an estimate of 

the additional electricity savings 

achievable from state policies not 

reflected in the 1.5 percent rate and the 

0.20 percent per year pace of 

improvement, such as building energy 

codes and state appliance standards, (2) 

alternative approaches and/or data 

sources (i.e., other than EIA Form 861) 

for determining each state’s current 

level of annual incremental electricity 

savings, and (3) alternative approaches 

and/or data sources for evaluating costs 

associated with implementation of state 

demand-side energy efficiency policies. 

5. Potential Emission Reduction 

Measures Not Used To Set Proposed 

Goals 

There are four additional potential 

measures for reducing, or supporting 

reduced, GHG emissions from EGUs that 

the EPA does not propose to consider 

part of the best system of emission 

reduction adequately demonstrated for 

existing EGUs at this time and therefore 

has not used for goal-setting purposes, 

but that merit discussion here: Fuel 

switching at individual EGUs, carbon 

capture and storage (CCS), using 

expanded amounts of less carbonintensive new NGCC capacity to provide 

replacement generation, and heat rate 

improvements at affected EGUs other 

than coal-fired steam EGUs. 

a. Fuel Switching at Individual Units 

One technically feasible approach for 

reducing CO2 emissions per MWh of 

generation from an EGU designed for 

coal-fired generation is to substitute 

natural gas for some or all of the coal. 

Most existing coal-fired steam EGU 

boilers can be modified to switch to 100 

percent gas input or to co-fire gas with 

coal in any desired proportion. For 

certain individual EGUs, switching to or 

co-firing with gas may be an attractive 

option for reducing CO2 emissions. 

Changing the type of fuel burned at a 

steam EGU typically requires certain 

plant modifications (e.g., new burners) 

and may have some negative impact on 

the net efficiencies of the boiler and the 

overall generation process. If the plant 

lacks existing gas pipeline infrastructure 

capable of delivering the necessary 

quantities of natural gas to the boiler, 

installation of a new pipeline lateral 

would also be required. 

The capital costs of plant 

modifications required to switch a coalfired EGU completely to natural gas are 

roughly $100–300/kW, excluding 

pipeline costs. For plants that require 

additional pipeline capacity, the capital 

cost of constructing new pipeline 

laterals is approximately $1 million per 

mile of pipeline built. Offsetting these 

capital costs, conversion to 100 percent 

gas input would typically reduce the 

EGU’s fixed operating and maintenance 

costs by about 33 percent due mainly to 

certain equipment retirements and a 

reduction in staffing, while non-fuel 

variable costs would be reduced by 

about 25 percent due to reduced 

maintenance and waste disposal costs. 

However, in most cases, the most 

significant cost change associated with 

switching from coal to gas in a coal-fired 

boiler is likely to be the difference in 

fuel cost. Using EIA’s projections of 

future coal and natural gas prices, 

switching a steam EGU’s fuel from coal 

to gas typically would more than double 

the EGU’s fuel cost per MWh of 

generation. 

The CO2 reduction potential of 

natural gas co-firing or conversion is 

due largely to the different carbon 

intensities of coal and natural gas and 

is directly related to the proportion of 

gas burned. Greater reductions in the 

CO2 emission rate are achieved at higher 

proportions of gas usage. For example, 

at ten percent gas co-firing, the net 

emission rate (e.g., pounds of CO2 per 

net MWh of generation) of a typical 

steam EGU previously burning only coal 

would decrease by approximately four 

percent. At 100 percent gas burn, the net 

emission rate of a typical steam EGU 

previously burning only coal would 

decrease by approximately 40 percent. 

For a typical base-load coal-fired 

EGU, and reflecting EIA’s projected 

future natural gas and coal prices, the 

average cost of CO2 reductions achieved 

through gas conversion or co-firing 

ranges from $83 per metric ton to $150 

per metric ton. The low end of the range 

of CO2 reduction costs represents a 100 

percent switch to gas, because in 

instances where a combination of coal 

and gas is burned, the EGU would 

continue to bear the fixed costs 

associated with equipment needed for 

coal combustion, raising the cost per ton 

of CO2 reduced. 

The EPA’s economic analysis suggests 

that there are more cost effective 

opportunities for coal-fired utility 

boilers to reduce their CO2 emissions 

than through natural gas conversion or 

co-firing. As a result, the EPA has not 

proposed at this time to include this 

option in the BSER and has not 

incorporated implementation of the 

option into the proposed state goals. 

However, the EPA believes that there 

are a number of factors that warrant 

further consideration in determining 

whether the option should be included. 

First, the EPA is aware that a number of 

utilities have reworked some of their 

coal-fired units to allow for some level 

of natural gas co-firing (and in some 

cases have converted the units to fire 

entirely on natural gas). Second, the 

EPA is aware of several possible reasons 

beyond reduction of CO2 emissions that 

may make natural gas co-firing 

economically attractive in some 

circumstances. One example is that 

natural gas reburn strategies that involve 


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190This is also sometimes referred to as ‘‘carbon 

capture and sequestration.’’ 

191For purposes of this proposal, NGCC units that 

have commenced construction as of January 8, 2014 

are ‘‘existing’’ units. 

192Whether and to what extent adding new NGCC 

capacity is likely to lead to CO2 reductions depends 

on what incentives would exist to operate that new 

capacity in preference to operation of more carbonintensive existing EGUs. Because the proposed state 

goals also reflect the opportunity to reduce 

utilization of high carbon-intensity EGUs by 

shifting generation to less carbon-intensive EGUs, 

we believe that in the context of a comprehensive 

state plan, the necessary incentives would likely 

exist, in which case adding new NGCC capacity 

would tend to reduce CO2 emissions. 

co-firing with 10 to 20 percent natural 

gas can be an effective control strategy 

for NOX emissions and, thus, can offset 

operational (and in some cases, capital) 

costs associated with other NOX

controls such as selective catalytic 

reduction (SCR) or selective noncatalytic reduction (SNCR). A second 

example suggested by some vendors is 

that the capability to burn natural gas in 

a coal-fired boiler can improve 

economics because it allows the boiler 

to operate more effectively at lower 

loads. A third example, applicable to 

units that run infrequently but may be 

needed for reliability purposes, is that 

converting to or co-firing with natural 

gas may be more economically attractive 

than either installing non-CO2 emission 

controls or taking other measures, such 

as transmission upgrades, that could 

become necessary if the unit were 

retired. Finally, beyond the reasons just 

described explaining why EGU owners 

may find natural gas co-firing to be costeffective, there are also potentially 

significant health co-benefits associated 

with burning natural gas instead of coal. 

We solicit comment on whether 

natural gas co-firing or conversion 

should be part of the BSER. We also 

request comment regarding whether, 

and, if so, how, we should consider the 

co-benefits of natural gas co-firing in 

making that determination. 

b. Carbon Capture and Storage 

Another possible approach for 

reducing CO2 emissions from existing 

fossil fuel-fired EGUs is through the 

application of carbon capture and 

storage 190 technology (CCS). In the 

recently proposed standards of 

performance for new fossil fuel-fired 

EGUs (79 FR 1430), the EPA proposed 

to find that the best system of emission 

reduction for new fossil fuel-fired 

boilers and IGCC units is partial 

application of CCS. In that proposal, the 

EPA found that, for new units, partial 

CCS has been adequately demonstrated, 

it is technically feasible, it can be 

implemented at costs that are not 

unreasonable, it provides meaningful 

emission reductions, and its 

implementation will serve to promote 

further development and deployment of 

the technology. The EPA also noted in 

the proposal that most of the relatively 

few new boiler and IGCC EGU projects 

currently under development are 

already planning to implement CCS, 

and, as a result, the proposed standard 

would not have a significant impact on 

nationwide energy prices. 

In contrast, the EPA did not identify 

full or partial CCS as the BSER for new 

natural gas-fired stationary combustion 

turbines, noting technical challenges to 

implementation of CCS at NGCC units 

as compared to implementation at new 

solid fossil fuel-fired sources. The EPA 

also noted that, because virtually all 

new fossil fuel-fired power projects are 

projected to use NGCC technology, 

requiring full or partial CCS would have 

a greater impact on the price of 

electricity than requiring CCS at the few 

projected coal plants, and the larger 

number of NGCC projects would make 

a CCS requirement difficult to 

implement in the short term. 

Partial CCS has been demonstrated at 

existing EGUs. It has been demonstrated 

at a pilot-scale at Southern Company’s 

Plant Barry, it is being installed for 

large-scale demonstration at NRG’s W.A. 

Parish facility, and it is expected soon 

to be applied at a commercial scale as 

a retrofit at SaskPower’s Boundary Dam 

plant in Canada. However, the EPA 

expects that the costs of integrating a 

retrofit CCS system into an existing 

facility would be substantial. For 

example, some existing sources have a 

limited footprint and may not have the 

land available to add a CCS system. 

Moreover, there are a large number of 

existing fossil-fired EGUs. Accordingly, 

the overall costs of requiring CCS would 

be substantial and would affect the 

nationwide cost and supply of 

electricity on a national basis. 

For the reasons just described, based 

on the information available at this 

time, the EPA does not propose to find 

that CCS is a component of the best 

system of emission reduction for CO2

emissions from existing fossil fuel-fired 

EGUs. The EPA does solicit comment on 

all aspects of applying CCS to existing 

fossil fuel-fired EGUs (in either full or 

partial configurations), but does not 

expect to finalize CCS as a component 

of the BSER in this rulemaking. It 

should be noted, however, that in light 

of the fact that several existing fossilfired EGUs are currently being 

retrofitted with CCS, the 

implementation of partial CCS may be a 

viable GHG mitigation option at some 

facilities, and as a result, emission 

reductions achieved through use of the 

technology could be used to help meet 

the emission performance level required 

under a state plan. 

Additional discussion can be found in 

the Greenhouse Gas Abatement 

Measures TSD. 

c. New NGCC Capacity 

In Section VI.C.2 above, we discussed 

the opportunity to reduce CO2

emissions by replacing generation at 

high carbon-intensity affected EGUs 

with lower-carbon generation from 

existing NGCC units.191 From a 

technical perspective, the same 

potential would exist to replace highemitting generation with generation 

from additional NGCC capacity that may 

be built in the future; the analysis above 

regarding the feasibility of policies to 

increase utilization rates of existing 

NGCC units on average to 70 percent 

applies equally to new NGCC units.192

We view the opportunity to reduce CO2

emissions at affected EGUs by means of 

addition and operation of new NGCC 

capacity as clearly feasible. 

In addition, we note that our 

compliance modeling for this proposal 

suggests that the construction and 

operation of new NGCC capacity will be 

undertaken as method of responding to 

the proposal’s requirements. 

However, compared to the 

opportunity to reduce CO2 emissions at 

affected EGUs by means of re-dispatch 

to existing NGCC capacity, the parallel 

opportunity involving new NGCC 

capacity would be more costly for 

several reasons. The first reason is the 

additional cost associated with 

additional usage of natural gas. As noted 

in the discussion of building block 2 

above, the EPA analyzed costs 

associated with several different target 

utilization rates for existing NGCC units 

and that analysis showed higher costs of 

CO2 reductions at higher target NGCC 

utilization rates. 

The second reason that emission 

reductions from the use of new NGCC 

capacity would be more costly is that 

there would be capital investment costs. 

Some amount of new NGCC capacity 

(beyond the units that were already 

under construction as of January 8, 2014 

and are ‘‘existing’’ units for purposes of 

this proposal) would likely be built to 

meet perceived electricity market 

demand or to replace less economic 

capacity regardless of this proposal. The 

costs of achieving CO2 emission 

reductions through re-dispatch to these 

new NGCC units and through redispatch to existing NGCC units would 

be comparable (ignoring consideration 


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193For convenience, the discussion in this 

Section VI.D is based on our proposal to identify 

the BSER as consisting of the building blocks 

themselves. The points made in this discussion are 

also relevant for our alternative proposal to identify 

the BSER as consisting of building block 1 coupled 

with reduced utilization of the affected EGUs in 

specified amounts. 

of the cost impacts just discussed 

related to increases in overall gas usage). 

However, in the case of any new NGCC 

units that would not have been built if 

not for this proposal, and that were built 

in part for the purpose of achieving CO2

reductions at affected EGUs, some 

portion of their construction or fixed 

operating costs would also be 

attributable to the CO2 reduction 

opportunity, increasing to some extent 

the cost of the CO2 reductions at 

affected EGUs achieved through redispatch to those new NGCC units. 

The third reason relates to the costs of 

pipeline infrastructure expansion, and 

in particular the unevenly distributed 

nature of those costs. While expanded 

use of existing NGCC capacity to 

achieve CO2 emission reductions can be 

expected to rely largely on existing 

pipeline infrastructure with incremental 

capacity expansions, use of new NGCC 

capacity—if required in all states— 

could require substantially greater 

pipeline infrastructure investments to 

serve some states than others. 

Taken together, the EPA believes the 

cost considerations just described 

indicate a higher cost for CO2 reductions 

achievable from re-dispatch to new 

NGCC capacity than from other options, 

at least for states with limited natural 

gas pipeline infrastructure, and we 

therefore do not propose to include this 

option in state goals. 

While the EPA is not proposing that 

new NGCC capacity is part of the basis 

supporting the BSER, we recognize that 

there are a number of new NGCC units 

being proposed and that many modeling 

efforts suggest that development of new 

NGCC capacity would likely be used as 

a CO2 emission mitigation strategy. 

Therefore, we invite comment on 

whether we should consider 

construction and use of new NGCC 

capacity as part of the basis supporting 

the BSER. Further, we take comment on 

ways to define appropriate state-level 

goals based on consideration of new 

NGCC capacity. 

d. Assessment of Heat Rate 

Improvement Opportunities at Oil-Fired 

Steam EGUs, Gas-Fired Steam EGUs, 

NGCC Units, and Simple-Cycle 

Combustion Turbine Units 

The EPA assessed opportunities to 

improve heat rates at affected EGUs 

other than coal-fired steam units. This 

assessment, which is documented in a 

Technical Memorandum included as an 

appendix to the GHG Abatement 

Measures TSD, considers the potential 

extent of heat rate improvements and 

CO2 reductions that could be reasonably 

available from oil-fired steam EGUs, gasfired steam EGUs, NGCC units, and 

simple-cycle combustion turbine units. 

For these non-coal technologies, the 

total additional potential CO2

reductions achievable through heat rate 

improvements appear relatively small 

compared to the potential CO2

reductions achievable through heat rate 

improvements at coal-fired steam EGUs. 

For this reason, the EPA does not 

propose to include heat rate 

improvement opportunities at these 

other fossil fuel-fired units as an 

element of the BSER for CO2 emissions 

from affected EGUs at this time. 

However, we are aware that the 

proportion of total generation provided 

from EGUs such as oil-fired steam EGUs 

or gas-fired steam EGUs varies by 

location, and may be relatively large in 

geographically isolated areas such as 

islands. We therefore invite comment on 

whether heat rate improvements for 

some of the EGU types discussed above 

should be identified as a basis for 

supporting the BSER, with particular 

reference to U.S. territories. 

Finally, the EPA expects that for some 

individual oil/gas-fired steam EGUs and 

NGCC units attractive heat rate 

improvement opportunities will exist. 

We note that under the proposed 

flexible approach to state plans 

described later in this preamble, CO2

reductions achieved through such 

opportunities could be used to help 

meet state goals, regardless of whether 

these measures are used as a basis to 

support the BSER. 

D. Potential Combinations of the 

Building Blocks as Components of the 

Best System of Emission Reduction 

This subsection summarizes the 

EPA’s examination of combinations of 

the building blocks as components of 

the BSER, comparing the merits of a 

potential BSER that comprises only 

building blocks 1 and 2 with the merits 

of a BSER that comprises all four 

building blocks—the preferred option in 

this proposal. (A more detailed 

discussion of how we evaluated each 

option against the criteria to be 

considered for the BSER follows in 

Section VI.E.) 193

1. Reasons for Considering 

Combinations of Building Blocks 

As previously described, the building 

blocks can be summarized as follows: 

Building block 1: Reducing the carbon 

intensity of generation at individual 

affected EGUs through heat rate 

improvements. 

Building block 2: Reducing emissions 

from the most carbon-intensive affected 

EGUs in the amount that results from 

substituting generation at those EGUs 

with generation from less carbonintensive affected EGUs (including 

NGCC units under construction). 

Building block 3: Reducing emissions 

from affected EGUs in the amount that 

results from substituting generation at 

those EGUs with expanded low- or zerocarbon generation. 

Building block 4: Reducing emissions 

from affected EGUs in the amount that 

results from the use of demand-side 

energy efficiency that reduces the 

amount of generation required. 

The EPA initially considered a BSER 

comprising only strategies within 

building block 1. As described earlier in 

Section VI.B, the EPA concluded that 

certain strategies within building block 

1—specifically heat rate improvements 

at individual coal-fired steam EGUs— 

should be a component of the BSER 

determination, as they are technically 

feasible and can be implemented at a 

reasonable cost. However, the EPA 

further concluded that, while heat rate 

improvements qualify as a system of 

emission reduction, they are not in 

themselves the BSER as there are 

additional strategies that can be utilized 

in combination with building block 1 

that are technically feasible, can be 

implemented at reasonable cost, and 

result in greater emission reductions 

than would be achieved through 

building block 1 strategies alone. The 

EPA is also concerned that if the 

measures that improve heat rates at 

coal-fired steam EGUs in building block 

1 are implemented in isolation, without 

additional measures that reduce overall 

electricity demand or encourage 

substitution of less carbon-intensive 

generation for more carbon-intensive 

generation, the resulting increased 

efficiency of coal-fired steam units 

would provide incentives to operate 

those EGUs more, leading to smaller 

overall reductions in CO2 emissions. 

Further, in listening sessions and other 

outreach meetings, the EPA learned that 

states and other sources were already 

implementing and pursuing strategies in 

the other building blocks for the 

purpose, at least in part, of reducing 

CO2 emissions. 

2. A Combination of Building Blocks 1 

and 2 as the Best System of Emission 

Reduction 

We considered a BSER that comprises 

strategies from building blocks 1 and 2. 


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In this system, emission reductions at 

the most carbon-intensive individual 

affected EGUs would occur through a 

combination of heat rate improvements 

(resulting in a decrease in emission 

rates) and substitution of generation at 

less carbon-intensive affected EGUs, 

notably existing NGCC units. One 

reason for considering a BSER 

comprising these two building blocks is 

that it involves only affected EGUs and 

generation from affected EGUs. 

The EPA believes that the 

combination of building blocks 1 and 2 

would be a ‘‘system of emission 

reduction’’ capable of achieving 

significant reductions in CO2 emissions 

from affected EGUs at a reasonable cost. 

As discussed in Section VI.C above, 

each of the two building blocks 

independently would be capable of 

achieving meaningful CO2 emission 

reductions at reasonable costs. In 

combination, the need to achieve the 

level of emission reductions achievable 

through use of building block 2 can 

mitigate the concern that building block 

1, implemented alone, would make 

coal-fired EGUs more economically 

competitive and lead to increased 

generation that would offset the 

emission reduction benefits of the 

carbon-intensity improvements. While 

combining the building blocks may also 

raise the cost per ton of emission 

reductions achieved through heat rate 

improvements (by reducing the quantity 

of MWh generated from the EGUs with 

improved heat rates and therefore also 

reducing the aggregate emission 

reductions achieved at those EGUs by 

the heat rate improvements), the costs of 

heat rate improvements are low enough 

that we believe their cost per ton of 

emission reduction would remain 

reasonable. 

Nevertheless, the EPA is not 

proposing that a combination of 

building blocks 1 and 2 is the BSER, 

because the proposed combination of all 

four building blocks discussed below— 

in other words, adding to the measures 

in building blocks 1 and 2 the measures 

in building blocks 3 and 4, which we 

and stakeholders have identified as 

already in use—is capable of achieving 

even greater CO2 emission reductions 

from affected EGUs at reasonable costs. 

The state-specific goals that would be 

computed consistent with a BSER based 

on the combination of only building 

blocks 1 and 2 (i.e., goals computed 

using the goal computation 

methodology discussed in Section VII 

below, except for the omission of 

building blocks 3 and 4) are presented 

in the Goal Computation TSD available 

in the docket. Further information on 

the EPA’s evaluation of this 

combination is available in the 

‘‘Analysis of Emission Reductions, 

Costs, Benefits and Economic Impacts 

Associated with Building Blocks 1 and 

2’’ available in the docket. We invite 

comment on a potential BSER 

comprising a combination of building 

blocks 1 and 2. 

3. A Combination of all Four Building 

Blocks as the Best System of Emission 

Reduction 

Our proposal for the BSER is a 

combination of all four building blocks. 

As discussed in Section VI.C above, 

each of the four building blocks is a 

proven way to support either 

improvements in emissions rates at 

affected EGUs or reductions in EGU 

mass emissions; each is in widespread 

use and is independently capable of 

supporting significant CO2 reductions 

from affected EGUs, either on an 

emission rate or mass-emissions basis, 

at a reasonable cost consistent with 

ensuring system reliability. As 

discussed in Section VI.E below, the 

combination of all four building blocks 

provides the basis for satisfying the legal 

criteria to be considered the BSER. 

Further, as discussed in Section X 

below, the combination of all four 

building blocks can achieve greater 

overall CO2 emission reductions from 

affected EGUs, at a lower cost per unit 

of CO2 eliminated, than the combination 

of building blocks 1 and 2. 

In the large and highly integrated 

electricity system, where electricity is 

fungible and the demand for electricity 

services can be met in many ways 

(including through demand-side energy 

efficiency), states and the industry have 

long pursued a wide variety of strategies 

for ensuring that the demand for 

electricity services is met reliably, at 

reasonable costs, and in a manner 

consistent with evolving constraints, 

including environmental objectives. 

These strategies have long extended to 

the measures in all four building blocks. 

We believe the combination of all four 

building blocks fairly represents the 

range of measures that states and the 

industry will consider when developing 

state plans and strategies for reducing 

CO2 emissions from affected EGUs 

while continuing to meet demand for 

electricity services reliably and 

affordably. Therefore, we believe it is 

appropriate to consider that same 

combination as the BSER upon which 

the required CO2 standards of 

performance for affected EGUs should 

be based. 

E. Determination of the Best System of 

Emission Reduction 

1. Overview 

In this section, the EPA explains the 

‘‘best system of emission reduction . . . 

adequately demonstrated.’’ This 

explanation includes what the EPA 

proposes to determine as the BSER and 

why. In addition the EPA explains how 

the BSER forms the basis for each state’s 

overall emission limitation requirement, 

which the EPA determines as the state 

goal and the state adopts into its 

planning process as the emissions 

performance level. The emission 

performance level, in turn, constitutes 

the minimum degree of stringency for 

the standards of performance that, taken 

as a whole, the state must establish for 

its affected EGUs (or, if the state adopts 

the portfolio approach, for the 

requirements imposed on the affected 

EGUs and other entities). Through this 

process, the BSER informs the minimum 

stringency of the standards of 

performance, although the state retains 

flexibility in its allocation of emission 

limitations among its sources. As the 

EPA explains, central to this overall 

approach is the fact that the EPA applies 

the BSER on a state-wide basis, which 

is consistent with the interconnected 

nature of the electricity system. 

The EPA is proposing two alternative 

formulations for the BSER, each of 

which is based on, although in different 

ways, the four building blocks. Under 

the first approach, emission rate 

improvements and mass emission 

reductions at affected EGUs facilitated 

through the adoption of the four 

building blocks themselves meet the 

criteria for the BSER because they will 

amount to substantial reductions in CO2

emissions achieved while maintaining 

fuel diversity and a reliable, affordable 

electricity supply for the United States. 

Under the second approach, the BSER 

consists of building block 1 coupled 

with reduced utilization in specified 

amounts from, in general, higheremitting affected EGUs. Under this latter 

approach, the measures in building 

blocks 2, 3, and 4 serve to justify those 

amounts and the ‘‘adequate[ ] 

demonstrat[ion]’’ because they are 

proven measures that are already being 

pursued by states and the industry, at 

least in part for the purpose of reducing 

CO2 emissions from affected EGUs. 

The remainder of this discussion is 

organized into the following 

subsections. Subsection 2 contains a 

summary of relevant considerations for 

the BSER as defined in the statute and 

further interpreted in court decisions. 

Subsection 3 discusses characteristics of 

the electricity industry relevant to 


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194Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 

(1974); Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d 427 (D.C. Cir. 1973), cert. denied, Appalachian 

Power Co. v. EPA, 416 U.S. 969 (1974); Sierra Club 

v. Costle, 657 F.2d 298 (D.C. Cir. 1981); Portland 

Cement Ass’n v. EPA, 665 F.3d 177 (D.C. Cir. 2011). 

Although this case law concerns the meaning of the 

definition of ‘‘standard of performance’’ for 

purposes of rulemakings that the EPA promulgated 

under CAA section 111(b), the same term is used 

for section 111(d), and as a result, this case law is 

relevant for the present rulemaking under section 

111(d). 

195As discussed in the January 2014 Proposal, the 

D.C. Circuit’s case law formulates the cost 

consideration in various ways: The costs must not 

be ‘‘exorbitant[ ]’’, Essex Chemical Corp. v. 

Ruckelshaus, 486 F.2d at 433, see Lignite Energy 

Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999); 

‘‘greater than the industry could bear and survive,’’ 

Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 

(D.C. Cir. 1975); or ‘‘excessive’’ or ‘‘unreasonable,’’ 

Sierra Club v. Costle, 657 F.2d at 343. In the January 

2014 Proposal, the EPA stated that ‘‘these various 

formulations of the cost standard . . . are 

synonymous,’’ and, for convenience, we used 

‘‘reasonableness’’ as the formulation. We take the 

same approach in this rulemaking. 

196See 1970 Senate Committee Report No. 91– 

1196 at 15 (‘‘The maximum use of available means 

of preventing and controlling air pollution is 

essential to the elimination of new pollution 

problems’’). 

197See Portland Cement Ass’n v. Ruckelshaus, 

486 F.2d at 391 (the best system of emission 

reduction must ‘‘look[ ] toward what may fairly 

be projected for the regulated future, rather than the 

state of the art at present’’). 

198See Sierra Club v. Costle, 657 F.2d at 351 

(upholding a standard of performance designed to 

promote the use of an emerging technology). 

199See Train v. Natural Res. Def. Council, 421 

U.S. 60 (1975). 

200See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12022 

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

Stationary Sources; Emission Guideline for Sulfuric 

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

Pulp Mills, Notice of Availability of Final Guideline 

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

Aluminum Plants; Availability of Final Guideline 

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

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

interpretation of the BSER for purposes 

of this proposal, most notably the 

industry’s highly interconnected and 

integrated nature. Subsection 4 provides 

a discussion of how the building blocks 

would satisfy the BSER criteria in 

isolation or support the alternative 

formulation of the BSER as including 

reduced utilization in specified 

amounts. Subsection 5 evaluates two 

combinations of building blocks—a 

combination of building blocks 1 and 2, 

and the proposed combination of all 

four building blocks—against the BSER 

criteria, and explains why we propose 

that the combination of all four is the 

BSER. Subsection 6 addresses 

additional considerations related to the 

inclusion of building blocks 2, 3, and 4 

as parts of the basis supporting the 

BSER. In subsection 7, we describe and 

seek comment on the alternate 

interpretation that the BSER includes, in 

addition to building block 1, a 

component consisting of reduced 

generation from higher-emitting affected 

EGUs, with the measures in the other 

building blocks serving as the basis for 

quantifying the amounts of generation 

reductions and consequent CO2

emission reductions that can be 

achieved while continuing to meet the 

demand for electricity services in a 

reliable and affordable manner. In 

subsection 8, we discuss the discretion 

that the case law gives us in weighing 

the various criteria to determine the 

BSER. In subsection 9, we discuss how 

the BSER and the state-wide manner in 

which the EPA applies it form the basis 

for the emission standards that the state 

includes in the plan, and we explain 

why that approach is consistent with 

the applicable section 111 requirements. 

The final three subsections address the 

topics of combining source categories, 

severability, and certain other specific 

issues on which we are seeking 

comment. Additional discussion is 

provided in the Legal Memorandum 

available in the docket. 

2. Statutory and Regulatory Provisions 

Related to Determination and 

Application of the BSER 

The EPA’s explanation for this BSER 

proposal begins with the statutory 

definition of a ‘‘standard of 

performance’’: 

The term ‘‘standard of performance’’ means 

a standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any nonair 

quality health and environmental impact and 

energy requirements) the Administrator 

determines has been adequately 

demonstrated. 

42 U.S.C. 7411(a)(1). 

The U.S. Court of Appeals for the D.C. 

Circuit (D.C. Circuit or Court) has 

handed down case law over a 40-year 

period that interprets this CAA 

provision, including its component 

elements.194 Under this case law, the 

EPA determines the BSER based on the 

following key considerations, among 

others: 

• The system of emission reduction 

must be technically feasible. 

• The EPA must consider the amount 

of emission reductions that the system 

would generate. 

• The costs of the system must be 

reasonable. The EPA may consider costs 

at the source level, the industry level, 

and, at least in the case of the power 

sector, the national level in terms of the 

overall costs of electricity and the 

impact on the national economy over 

time.195

• The EPA must also consider that 

CAA section 111 is designed to promote 

the development and implementation of 

technology, including the diffusion of 

existing technology as the BSER,196 the 

development of new technology that 

may be treated as the BSER,197 and the 

development of other emerging 

technology.198

Another consideration particularly 

relevant to this rulemaking is energy 

impacts, which, as with costs, the EPA 

may consider at the source level, the 

industry level, and the national level 

over time. In the context of the 

electricity industry and this proposal, 

the EPA believes that the scope of 

energy impacts that may be considered 

encompasses assurance of the continued 

ability of the industry to meet the 

evolving demand for electricity services 

in a reliable manner, while providing 

sufficient flexibility to enable affected 

sources to follow state energy plans. 

Importantly, the EPA has discretion to 

weigh these various considerations, may 

determine that some merit greater 

weight than others, and may vary the 

weighting depending on the source 

category. 

It is a well-established principle that 

states have discretion regarding the 

measures adopted in their state 

implementation plans under CAA 

section 110 to attain the NAAQS.199 The 

EPA believes that the same principle 

applies in the context of state plans 

under section 111(d) as well, such that 

each state has the discretion to adopt 

emission reduction measures other than 

the measures found by the EPA to 

comprise the BSER, or to place greater 

or lesser emphasis than the EPA on 

certain measures, provided that the 

state’s plan achieves the required level 

of emission performance for affected 

sources. 

The EPA discussed the CAA 

requirements and Court interpretations 

of the BSER at length in the January 

2014 Proposal, 79 FR at 1,462/1–1,467/ 

3, and incorporates by reference that 

discussion into this rulemaking. 

Over the last forty years, under CAA 

section 111(d), the agency has regulated 

four pollutants from five source 

categories (i.e., phosphate fertilizer 

plants (fluorides), sulfuric acid plants 

(acid mist), primary aluminum plants 

(fluorides), Kraft pulp plants (total 

reduced sulfur), and municipal solid 

waste landfills (landfill gases)).200 In 

addition, the agency has regulated 

additional pollutants under CAA 


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201See, e.g., ‘‘Standards of Performance for New 

Stationary Sources and Emission Guidelines for 

Existing Sources: Sewage Sludge Incineration Units, 

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

202 In the Regional Greenhouse Gas Initiative, 

described in more detail below, participating states 

use emission budgets and a trading program to 

address CO2 emissions from the electricity sector. 

203 In addition to the already-implemented 

programs mentioned above—the SO2-related 

portion of the Acid Rain Program, the OTC NOX

Budget Program, the NOX SIP Call NOX Budget 

Trading Program, and the Clean Air Interstate Rule 

trading programs—use of measures in the building 

blocks would also facilitate compliance with the 

cap-and-trade programs established by the CrossState Air Pollution Rule (76 FR 48208, Aug. 8, 

2011). 

204A number of utilities also have climate 

mitigation plans. Examples include National Grid, 

http://www2.nationalgrid.com/responsibility/howwere-doing/grid-data-centre/climate-change/; 

Exelon, http://www.exeloncorp.com/newsroom/pr_

20140423_EXC_Exelon2020.aspx; PG&E, http://

www.pge.com/about/environment/pge/climate/; 

and Austin Energy, http://austinenergy.com/wps/

portal/ae/about/environment/austin-climateprotection-plan/!ut/p/a0/04_Sj9CPykssy0xPLM

nMz0vMAfGjzOINjCyMPJwNjDzdzY0sDBzdnZ28Tc

P8DAMMDPQLsh0VAU4fG7s!/. 

205State of California Global Warming Solutions 

Act of 2006, Assembly Bill 32, http://www.leginfo.

ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_

bill_20060927_chaptered.pdf. 

206 December 27, 2013 Letter from Mary D. 

Nichols, Chairman of California Air Resources 

Board, to EPA Administrator Gina McCarthy. 

207See Cal. Air Res. Bd., Climate Change Scoping 

Plan 31–32, 41–46 (2008), available at http://www.

arb.ca.gov/cc/scopingplan/document/adopted_

scoping_plan.pdf. 

section 111(d) in conjunction with CAA 

section 129.201 However, the agency has 

not previously regulated CO2 or any 

other greenhouse gas under CAA section 

111(d) (although because landfill gases 

include methane, the agency’s 

regulation of landfill gases reduced 

emissions of that greenhouse gas). 

Further, the electricity industry differs 

in important ways from the source 

categories previously regulated under 

section 111(d) in terms of its large scale, 

its central importance to the economy, 

and, as discussed below, its highly 

interconnected and integrated nature. 

3. The Interconnected Nature of the U.S. 

Electricity Sector 

The U.S. electricity system is a highly 

interconnected, integrated system in 

which large numbers of EGUs using 

diverse fuels and generating 

technologies are operated in a 

coordinated manner to produce fungible 

electricity services for customers. 

Because electricity storage is costly and 

has not been widely deployed, the 

amounts of electricity demanded and 

supplied must be continuously 

matched, and system operators typically 

have flexibility to choose among 

multiple EGUs when selecting where to 

obtain the next MWh of generation 

needed. Coordination over short- and 

long-term time scales is accomplished 

through a variety of institutions 

including vertically integrated utilities, 

state regulatory agencies, independent 

system operators and regional 

transmission organizations (ISOs/RTOs), 

and market mechanisms. The electricity 

sector is both critical to the nation’s 

economy and the source of more than 30 

percent of U.S. greenhouse gas 

emissions, predominantly in the form of 

CO2. 

The integrated electricity system 

allows increased generation from less 

carbon-intensive NGCC units to 

substitute for generation from more 

carbon-intensive steam EGUs (building 

block 2), thereby lowering CO2

emissions from the group of affected 

EGUs as a whole. The electricity system 

similarly allows increased generation 

resulting from expansion of the amount 

of available low- or zero-carbon 

generating capacity connected to the 

electric grid (building block 3), as well 

as avoided generation resulting from 

reductions in electricity demand 

(building block 4), to substitute for fossil 

fuel-fired generation, thereby reducing 

CO2 emissions from affected EGUs. Each 

of these measures already routinely 

occurs within this integrated system for 

providing electricity and electricity 

services. 

The integrated nature of the electricity 

system has long played a central role in 

the industry’s continuing efforts to 

assure reliability and to manage costs 

generally. Specifically in the area of 

pollution control, state governments and 

the federal government have repeatedly 

taken advantage of the integrated nature 

of the electricity system when designing 

programs to allow the industry to meet 

the pollution control objectives in a 

least-cost manner. Examples include 

several cap-and-trade programs to 

reduce national or regional emissions of 

SO2 and NOX: The SO2-related portion 

of the CAA Title IV Acid Rain Program, 

the Ozone Transport Commission (OTC) 

NOX Budget Program, the NOX SIP Call 

NOX Budget Trading Program, and the 

Clean Air Interstate Rule (CAIR) annual 

SO2, annual NOX, and ozone-season 

NOX trading programs. While the Acid 

Rain Program was created by federal 

legislation, the OTC NOX Budget 

Program was developed primarily 

through the joint efforts of a group of 

northeastern states. In the NOX SIP Call 

and CAIR programs, the federal 

government set emission budgets and 

developed trading programs that states 

could use as a compliance option.202

Each of these programs was designed to 

take advantage of the fact that in an 

integrated electricity system, some 

EGUs can reduce emissions at lower 

costs than others, and that by allowing 

the industry to determine through 

market mechanisms which EGUs to 

control and which to leave 

uncontrolled, and which EGUs to 

potentially operate more and which to 

potentially operate less, overall 

compliance costs can be reduced. The 

integrated electricity system plays the 

important function of allowing some 

EGUs to reduce their generation while 

ensuring that overall demand for 

electricity services can be reliably met. 

It is worth noting that adoption by 

affected EGUs of any of the measures in 

the building blocks could be (or could 

have been) used to facilitate compliance 

with each of the programs just 

described.203

Some states are already relying on the 

integrated nature of the electricity 

system to establish the policy contexts 

within which affected EGUs will reduce 

their CO2 emissions.204 California and 

Colorado provide two examples of how 

statewide targets (or company-wide 

targets within a state) can be designed 

with consideration of the wide range of 

CO2 mitigation options and affected 

EGUs’ flexibility to use those options. 

California enacted its Global Warming 

Solutions Act (also known as AB32) in 

2006, requiring the state to reduce its 

GHG emissions to 1990 levels by 2020 

and 80 percent below 1990 levels by 

2050.205 According to California, ‘‘the 

integrated nature of the power grid 

means that policies which displace the 

need for fossil generation can often cut 

emissions from covered sources more 

deeply, and more cost-effectively than 

can engineering changes at the plants 

alone, though these source-level control 

efforts are a vital starting point.’’ 206

California therefore relied on a suite of 

mechanisms to provide fossil fuel-fired 

generation substitutes and incentives for 

EGUs to reduce their emissions, 

including demand-side energy 

efficiency programs, renewable energy 

programs, and an economy-wide capand-trade program, along with other 

programs.207 The California plan has 

put in place mechanisms that through 

market dynamics affect both companies’ 

longer-term planning decisions and 

their short-term dispatch decisions. The 

need to hold emissions allowances and 

the reduced demand from demand-side 

energy efficiency programs impact 

longer-term decisions companies make 

about investment in both existing and 

new EGUs. The price of emission 

allowances also impacts hourly dispatch 

decisions; where emission allowance 

requirements are in effect, EGU owners 


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208The requirement to hold allowances covering 

their CO2 emissions went into effect for EGUs in 

California on January 1, 2013. 

209The law also set some explicit requirements, 

such as requirements for development of new 

renewable generating capacity and requirements to 

phase out older coal-fired EGUs. 

210See State of Colorado House Bill 10–1365, 

available at http://www.leg.state.co.us/clics/

clics2010a/csl.nsf/fsbillcont/0CA296732C8CEF4

D872576E400641B74?Open&file=1365_ren.pdf. 

211Participating states include Connecticut, 

Delaware, Maine, Maryland, Massachusetts, New 

Hampshire, New York, Rhode Island, and Vermont. 

212See RGGI Web site at http://www.rggi.org/rggi. 

213Potential heat rate improvements create 

opportunities for EGU owners to reduce their 

variable costs, which increase potential operating 

profits from generation and thereby create 

opportunities to lower the prices at which the 

owners would bid the capacity of their EGUs into 

the auctions. 

routinely recognize the costs of 

emission allowances as components of 

the variable operating costs that are 

relied on for these decisions.208 In this 

manner, allowance prices constitute 

market signals encouraging reduced use 

of higher-emitting EGUs and increased 

use of lower-emitting EGUs. 

The Colorado Clean Air, Clean Jobs 

Act (CACJA), signed into law on April 

19, 2010, required each investor-owned 

utility with coal-fired EGUs to submit to 

the state a multi-pollutant plan for 

meeting current and foreseeable EPA 

standards for emissions of NOX, SO2, 

particulates, mercury, and CO2. Rather 

than fully prescribing specific control 

technologies, the law provided 

flexibility for each utility to select the 

best set of measures to achieve the 

emission reductions.209 For example, a 

utility could choose to retrofit or 

repower EGUs, or it could choose to 

retire higher-emitting EGUs and replace 

them with NGCC units and other lowor non-emitting energy plants or with 

end-use efficiency measures.210 The 

Colorado plan generally focused more 

on impacting companies’ longer-term 

planning decisions than on affecting 

short-term dispatch decisions. In 

response, Colorado utilities have 

adopted a mix of measures including 

retrofits, natural gas conversions and 

retirements of coal-fired EGUs, as well 

as construction of new NGCC units. 

Multi-state mechanisms with 

analogous impacts on both longer-term 

planning decisions and short-term 

dispatch decisions have also been put in 

place. For example, nine northeastern 

and Mid-Atlantic States 211 participate 

in the Regional Greenhouse Gas 

Initiative (RGGI), a market-based 

emissions budget trading program that 

sets an aggregate limit on CO2 emissions 

from fossil fuel-fired EGUs in the 

participating states. To comply with the 

program, each EGU must acquire 

allowances equal to its emissions in 

each compliance period—through 

purchases or by allocation from the 

state—and must surrender the 

allowances at the end of the period. The 

RGGI program offers flexibility to 

regulated parties through provisions for 

multi-year compliance periods, 

allowance banking, offsets, an auction 

reserve price, and a cost-containment 

reserve of allowances, and further 

encourages emission allowance market 

development by authorizing trading 

between regulated and non-regulated 

parties.212 Operating in this regime, 

EGUs could take a variety of compliance 

actions, including replacing generation 

at higher-emitting EGUs with generation 

at lower-emitting EGUs or achieving 

emissions reductions at EGUs by means 

of end-use energy efficiency programs. 

An approach to determination of the 

BSER that recognizes the integrated 

nature of the electricity system is also 

consistent with the way in which the 

electricity industry already addresses 

resource planning issues. For example, 

in states where the price of EGUs’ 

generation remains subject to regulation, 

utilities generally prepare integrated 

resource plans setting forth their 

strategies for meeting future demand for 

electricity services in a cost-effective 

manner. These plans may include 

measures from building blocks 2, 3, and 

4. In most states where generation is no 

longer subject to price regulation, 

regional transmission organizations 

(RTOs) or independent system operators 

(ISOs) ensure the adequacy of future 

generation supplies by administering 

auctions for forward capacity. In these 

auctions, owners of existing EGUs (with 

consideration of building blocks 1 and 

2),213 developers of new EGUs including 

renewable generating capacity (building 

block 3), and developers of demand-side 

resources (building block 4) all compete 

to provide potential resources for 

meeting the projected demand for 

electricity services. 

As indicated by the foregoing 

discussion, in the U.S. electricity system 

the demand for electricity services is 

met, on both a short-term and longerterm basis and in both regulated and 

deregulated contexts, through integrated 

consideration of a wide variety of 

possible options, coordinated by some 

combination of utilities, regulators, 

system operators, and market 

mechanisms. The EPA believes that the 

BSER for CO2 emissions from existing 

EGUs should reflect this integrated 

character. 

A final, important point regarding the 

integrated electricity system is that the 

sets of actions that enable the demand 

for electricity services to be 

continuously met can be undertaken in 

different orders, with changes in some 

interconnected elements eliciting 

compensating responses from other 

interconnected elements. Thus, the CO2

emissions reductions associated with 

building blocks 2, 3, and 4 can be 

achieved in either of two ways: (i) First 

instituting measures in building blocks 

2, 3, and 4, which, due to the 

interconnected and integrated nature of 

the grid, would elicit the response of 

reducing generation at some or all 

affected EGUs, thereby lowering those 

EGUs’ emissions; or (ii) first reducing 

generation and therefore emissions from 

some or all affected EGUs (or planning 

to make those reductions), which due to 

the interconnected and integrated 

nature of the grid, would elicit the 

responses identified in building blocks 

2, 3, and 4 of increasing generation at 

lower-emitting EGUs or reducing the 

demand for electricity services. (In some 

cases, the change and response could be 

planned simultaneously.) Each of these 

sets of actions, with the building blocks 

as the initial change or the reduced 

generation at affected EGUs as the initial 

change, may be considered to be part of 

a ‘‘system of emission reduction,’’ as 

discussed below. 

Further discussion of the ways in 

which the ‘‘system of emission 

reduction’’ for affected EGUs is 

influenced by the interconnected and 

integrated nature of the electricity 

system is provided below in the context 

of the EPA’s rationale for proposing to 

base the BSER on the combination of all 

four building blocks. This topic is also 

discussed in the Legal Memorandum 

available in the docket. 

4. Evaluation of Individual Building 

Blocks Against the BSER Criteria 

In this subsection we explain why (i) 

the individual building blocks meet the 

criteria to qualify as components of the 

‘‘best system of emission reduction . . . 

adequately demonstrated’’ and (ii) why, 

under the alternative formulation of the 

BSER as including reduced utilization 

of higher-emitting affected EGUs in 

specified amounts, building blocks 2, 3, 

and 4 serve as the basis for those 

amounts and why the reduced 

utilization is ‘‘adequately 

demonstrated.’’ 

a. Building Block 1—Heat Rate 

Improvements 

Building block 1—reducing the 

carbon intensity of generation at 

individual affected coal-fired steam 

EGUs through heat rate improvements— 

is a component of the BSER because the 

measures the affected sources may 


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214According to a DOE/NETL study, the relative 

amount of water consumption for a new pulverized 

coal plant is 2.5 times the consumption for a new 

NGCC unit of similar size. ‘‘Cost and Performance 

Baseline for Fossil Energy Plants: Volume 1: 

Bituminous Coal and Natural Gas to Electricity,’’ 

Rev 2a, September 2013, National Energy 

Technology Laboratory Report DOE/NETL–2010/

1397. 

215For purposes of this rulemaking, ‘‘existing’’ 

EGUs include units under construction as of 

January 8, 2014, the date of publication in the 

Federal Register of the Carbon Pollution Standards 

for new fossil fuel-fired EGUs. 

216Because building blocks 3 and 4 reduce 

generation and CO2 emissions from all fossil fuelundertake to achieve heat rate 

improvements are technically feasible 

and of reasonable cost, and meet the 

other requirements to qualify as a 

component of the ‘‘best system of 

emission reduction . . . adequately 

demonstrated.’’ 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of CO2 emission 

reductions achievable through heat rate 

improvements are discussed in Section 

VI.C.1 above. We consider heat rate 

improvement to be a common and wellestablished practice within the industry. 

Other BSER criteria also favor 

building block 1 as a component of the 

BSER. For example, with respect to nonair health and environmental impacts, 

heat rate improvements cause fuel to be 

used more efficiently, reducing the 

volumes of and therefore the adverse 

impacts associated with disposal of coal 

combustion solid waste products. With 

respect to technological innovation, 

building block 1 encourages the spread 

of more advanced technology to EGUs 

currently using components with older 

designs. The EPA has not specifically 

evaluated the extent to which enhanced 

maintenance practices leading to heat 

rate improvements might also lead to 

electricity reliability improvements, but 

generally expects that enhanced 

maintenance would be more likely to 

improve than to degrade EGU 

availability, which would tend to 

improve electricity system reliability. 

As noted above, the EPA is concerned 

about the potential ‘‘rebound effect’’ 

associated with building block 1 if 

applied in isolation. More specifically, 

we noted that in the context of the 

integrated electricity system, absent 

other incentives to reduce generation 

and CO2 emissions from coal-fired 

EGUs, heat rate improvements and 

consequent variable cost reductions at 

those EGUs would cause them to 

become more competitive compared to 

other EGUs and increase their 

generation, leading to smaller overall 

reductions in CO2 emissions (depending 

on the CO2 emission rates of the 

displaced generating capacity). 

However, we believe that this concern 

can be readily addressed by ensuring 

that the BSER also reflects other CO2

reduction strategies that encourage 

increases in generation from lower- or 

zero-carbon EGUs or in demand-side 

energy efficiency, thereby allowing 

building block 1 to be considered part 

of the BSER for CO2 emissions at 

affected EGUs. 

b. Building Block 2—Re-Dispatch 

Building block 2—reducing CO2

emissions at and substituting for 

generation from the most carbonintensive affected EGUs with generation 

from less carbon-intensive affected 

EGUs (specifically NGCC units that are 

currently operating or under 

construction)—is a component of the 

BSER because the shifts in generation 

that it involves demonstrate that 

reducing mass CO2 emissions at higheremitting EGUs is technically feasible, 

will not jeopardize system reliability, is 

of reasonable cost, and meets the other 

requirements for a component of the 

‘‘best system of emission reduction . . . 

adequately demonstrated.’’ 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of CO2 emission 

reductions achievable at high-emitting 

EGUs through re-dispatch among 

affected EGUs are discussed in Section 

VI.C.2 above. We consider re-dispatch 

among the large number of diverse 

EGUs that are linked to one another and 

to customers by extensive regional 

transmission grids to be a routine and 

well-established operating practice 

within the industry that is used to 

facilitate the achievement of a wide 

variety of objectives, including 

environmental objectives, while meeting 

the demand for electricity services. As 

discussed above, in the interconnected 

and integrated electricity industry, fossil 

fuel-fired steam EGUs are able to reduce 

their generation and NGCC units are 

able to increase their generation in a 

coordinated manner through 

mechanisms—in some cases centralized 

and in others not—that regularly deal 

with such changes on both a short-term 

and a longer-term basis. 

Both the achievability of this building 

block and the reasonableness of its costs 

are supported by the fact that there has 

been a long-term trend in the industry 

away from coal-fired generation and 

toward NGCC generation for a variety of 

reasons. As part of their CO2 reduction 

strategies, states can encourage this 

trend in a variety of ways. First, a state 

could use its permitting authority to 

impose limits on the hours of operation 

(or emissions) of individual steam 

generating units over a given time 

period. Second, a state could change the 

relative costs of generation for more 

carbon-intensive and less carbonintensive generating units by imposing 

a cost on carbon emissions. A state 

could do so through any of several 

market-based mechanisms. One would 

be to adopt an allowance-based system. 

An example is the Regional Greenhouse 

Gas Initiative, an allowance-based 

system in which sources purchase 

allowances in periodic auctions. 

Another way would be through a 

tradable emission rate system, under 

which the state would impose an 

emission rate limit on the steam 

generating unit that the unit could meet 

only by purchasing the right to average 

its emission rate with a unit with a 

lower rate, such as an NGCC unit. Most 

broadly, an allowance system would 

provide the greatest incentive for the 

most carbon-intensive affected sources 

to reduce emissions as much as possible 

so as to reduce their need to purchase 

allowances (or to allow them to sell unneeded allowances), and the same 

would be true for a tradable emission 

rate system. 

The emission reductions achievable 

or supported by the application of 

building block 2 also perform well 

against other BSER criteria. For 

example, we expect that building block 

2 would have positive non-air health 

and environmental impacts. Coal 

combustion for electricity generation 

produces large volumes of solid wastes 

that require disposal, with some 

potential for adverse environmental 

impacts; these wastes are not produced 

by natural gas combustion. The intake 

and discharge of water for cooling at 

many EGUs also carries some potential 

for adverse environmental impacts; 

NGCC units generally require less 

cooling water than steam EGUs.214 As 

already noted, with respect to energy 

impacts, the EPA believes that building 

block 2 (at least at the level of 

stringency proposed for purposes of 

establishing state goals) would not pose 

risks to reliability. Building block 2 also 

promotes greater use of the advanced 

NGCC technology installed in the 

existing fleet of NGCC units. 

It should be observed that, by 

definition of the elements of this 

building block, the shifts in generation 

taking place under building block 2 

occur entirely among existing EGUs 

subject to this rulemaking.215 Through 

application of this building block 

considered in isolation, some affected 

sources—mostly coal-fired steam 

EGUs—would reduce their generation 

and CO2 emissions, while other affected 

sources—NGCC units—would increase 

their generation and CO2 emissions.216


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fired affected EGUs as a group, including NGCC 

units, the increase in generation and CO2 emissions 

from NGCC units under building block 2 is 

mitigated to some extent by including those 

building blocks in the BSER along with building 

block 2. 

217See U.S. NRC, Watts Bar Unit 2 Final 

Environmental Statement, Final Report at 3–3, 

available at http://pbadupws.nrc.gov/docs/ML1314/ 

ML13144A092.pdf; U.S. NRC, Summer Units 2–3 

Final Environmental Impact Statement, Final 

Report at 3–14, available at http://

pbadupws.nrc.gov/docs/ML1109/

ML11098A044.pdf; U.S. NRC, Vogtle Units 3–4 

Final Environmental Impact Statement, Final 

Report at 3–5, available at http://pbadupws.nrc.gov/ 

docs/ML0822/ML082240145.pdf. Relative to the 

once-through systems at many existing power 

plants, closed-cycle cooling systems withdraw from 

and discharge to external water bodies substantially 

less overall cooling water, although they also 

consume larger amounts of water through 

evaporation. See Department of Energy/Office of 

Fossil Energy’s Power Plant Water Management 

R&D Program, available at http://www.netl.doe.gov/ 

File%20Library/Research/Energy%20Analysis/

Publications/PowerPlantWaterMgtR-D-Final-1.pdf. 

However, because for each MWh of 

generation, NGCC units produce less 

CO2 emissions than coal-fired steam 

EGUs, the total quantity of CO2

emissions from all affected sources in 

aggregate would decrease. In the context 

of the integrated electricity system, 

where the operation of affected EGUs of 

multiple types is routinely coordinated 

to provide a fungible service, and in the 

context of CO2 emissions, where 

location is a less important factor than 

is the case for other pollutants, the EPA 

believes that a measure that takes 

advantage of that integration to reduce 

CO2 emissions from the overall set of 

affected EGUs is readily encompassed 

within the meaning of a ‘‘system of 

emission reduction’’ for CO2 emissions 

at affected EGUs even if the measure 

would increase CO2 emissions from a 

subset of those affected EGUs. Indeed, 

our review of the data and discussions 

with states reveal that some states are 

already moving in this direction for this 

purpose (while others are moving in the 

same direction for other purposes). 

Emission trading or averaging 

approaches can facilitate the 

implementation of such a ‘‘system’’ and 

have already been used in the electricity 

industry to address CO2 as well as other 

pollutants, as discussed above. 

Finally, the EPA notes that the 

alternative interpretation of the BSER 

discussed later is based in part on the 

re-dispatch measures in building block 

2. In this alternative, as it relates to 

building block 2, reduced generation 

from the subset of affected EGUs 

consisting of fossil fuel-fired steam 

EGUs—i.e., the most carbon-intensive 

subset of affected EGUs—is a 

component of the BSER. The potential 

to use increased generation from less 

carbon-intensive affected NGCC units 

would serve as a basis for quantifying 

the amounts of generation reductions 

and CO2 emission reductions at more 

carbon-intensive affected EGUs that 

could be achieved while continuing to 

meet the demand for electricity services 

in a reliable and affordable manner. 

This alternative is discussed further in 

Section VI.E.7 below. 

c. Building Block 3—Use of Expanded 

Low- and Zero-Carbon Generating 

Capacity 

Building block 3—reducing CO2

emissions at and substituting for 

generation from affected EGUs by using 

expanded amounts of low- and zerocarbon generating capacity—is a 

component of the BSER because the 

expansion and use of renewable 

generating capacity, completion and use 

of nuclear capacity currently under 

construction, and avoidance of nuclear 

capacity retirements all establish the 

foundation for a determination that 

mass emission reductions from affected 

EGUs are technically feasible, do not 

jeopardize system reliability, are of 

reasonable cost, and meet the other 

requirements for a component of the 

‘‘best system of emission reduction . . . 

adequately demonstrated.’’ 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of the measures in 

building block 3 are discussed in 

Section VI.C.3 above. We consider all of 

these measures to be proven, wellestablished practices within the 

industry, and development of renewable 

capacity in particular is consistent with 

recent industry trends. States are 

already pursuing policies that encourage 

production of greater amounts of 

renewable energy, such as the 

establishment of targets for procurement 

of renewable generating capacity. 

Moreover, markets for renewable energy 

certificates, which facilitate investment 

in renewable energy, are already wellestablished. As noted above with redispatch, an allowance system or 

tradable emission rate system would 

provide incentives for sources to reduce 

their emissions as much as possible, 

including through substituting for their 

generation with generation from 

renewable energy. In addition, owners 

of existing nuclear units and nuclear 

units currently under construction can 

take action to complete or preserve that 

capacity, the generation from which 

likewise can be dispatched in a 

coordinated manner to substitute for 

fossil fuel-fired generation. As discussed 

above, coordination of these decisions 

in the integrated electricity system can 

occur through a variety of mechanisms, 

some centralized and some not. 

The renewable capacity measures in 

building block 3 generally perform well 

against other BSER criteria. For 

example, incentives for expansion of 

renewable capacity encourage 

technological innovation in improved 

renewable technologies as well as more 

extensive deployment of current 

advanced technologies. Generation from 

wind turbines (the most common 

renewable technology) does not produce 

solid waste or require cooling water, a 

better environmental outcome than if 

that amount of generation had instead 

been produced at a typical range of 

fossil fuel-fired EGUs. Although the 

intermittent nature of generation from 

renewable resources such as wind and 

solar units requires special 

consideration from grid operators, 

renewable generation has grown quickly 

in recent years, as discussed above, and 

the EPA has seen no evidence that 

operators will be less able to cope with 

future growth than they have with rapid 

past growth. 

The EPA believes that the 

performance of the nuclear measures in 

building block 3 against the other BSER 

measures is also positive on balance. 

With respect to encouragement of 

technological innovation, incentives for 

completion of nuclear capacity 

currently under construction encourage 

deployment of nuclear unit designs that 

reflect advances over earlier designs. 

The nation’s nuclear fleet today 

routinely operates at high average 

utilization rates, suggesting no reason to 

expect adverse reliability consequences 

from completion or preservation of 

additional nuclear capacity. The five 

nuclear units currently under 

construction are all designed to use 

closed-cycle cooling systems with lower 

cooling water usage than some existing 

fossil fuel-fired EGUs;217 existing 

nuclear units may use amounts of 

cooling water comparable to the 

amounts used by those fossil fuel-fired 

steam EGUs. The EPA recognizes that 

nuclear generation poses unique waste 

disposal issues (although it avoids the 

solid waste issues specific to coal-fired 

generation). However, we do not 

consider that potential disadvantage of 

nuclear generation relative to fossil fuelfired generation as outweighing nuclear 

generation’s other advantages as an 

element of building block 3. For all 

these reasons, we consider building 

block 3 to be a component of the ‘‘best 

system of emission reduction . . . 

adequately demonstrated.’’ 

Finally, the EPA notes that the 

alternative BSER discussed later would 

include a component consisting of 

reduced generation from affected EGUs, 


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218 If an EGU produces less generation output, 

then an improvement in that EGU’s heat rate and 

rate of CO2 emissions per unit of generation 

produces a smaller reduction in CO2 emissions. If 

the investment required to achieve the 

improvement in heat rate and emission rate is the 

same regardless of the EGU’s generation output, 

then the cost per unit of CO2 emission reduction 

will be higher when the EGU’s generation output 

is lower. 

with the measures in building block 3 

serving as a basis for quantifying the 

amount of reduced generation and 

consequent CO2 emission reductions. 

Because of the availability of those 

measures, the amount of reduced 

generation can be achieved while 

continuing to meet the demand for 

electricity services in a reliable and 

affordable manner. This alternative 

BSER is discussed in Section VI.E.7 

below. 

d. Building Block 4—Increased 

Demand-Side Energy Efficiency 

Building block 4—reducing CO2

emissions at and reducing generation 

from affected EGUs by promoting 

demand-side energy efficiency that 

reduces the amount of generation 

required from affected EGUs—is a 

component of the BSER because the 

demand-side energy efficiency is 

technically feasible and of reasonable 

cost, and meets the other requirements 

for a component of the ‘‘best system of 

emission reduction . . . adequately 

demonstrated.’’ 

The EPA’s analysis and conclusions 

regarding the technical feasibility, costs, 

and magnitude of building block 4 are 

discussed in Section VI.C.4 above. We 

consider demand-side energy efficiency 

programs to be proven, well-established 

practices within the industry that are 

consistent with industry trends. Greater 

demand-side energy efficiency is 

already a common policy goal among 

states, and most states already authorize 

or require implementation of demandside energy efficiency programs. Fossil 

fuel-fired EGUs can reduce their 

generation. Owners of affected EGUs as 

well as other parties can contract for 

demand-side energy efficiency. As 

discussed above, coordination of these 

decisions in the integrated electricity 

system can occur through a variety of 

mechanisms, some centralized and 

some not. For example, an allowance 

system or tradable emission rate system 

would provide incentives that promote 

the measures in building block 4 in the 

same manner as discussed above for 

other building blocks. 

Building block 4 is also very attractive 

under other BSER criteria. Demand-side 

energy efficiency avoids the non-air 

health and environmental effects of the 

fossil fuel-fired generation for which it 

substitutes. Further, by reducing the 

overall amount of electricity that needs 

to be transmitted between EGUs and 

customers, demand-side energy 

efficiency tends to relieve stress on the 

grid, thereby increasing system 

reliability. Creating incentives for 

additional demand-side energy 

efficiency is also consistent with the 

goals of encouraging technological 

innovation in energy efficiency and 

encouraging deployment of current 

advanced technologies. For all these 

reasons, the measures in building block 

4 qualify as a component of the ‘‘best 

system of emission reduction . . . 

adequately demonstrated.’’ 

The EPA notes that the alternative 

BSER discussed later would include a 

component consisting of reduced 

generation from affected EGUs, with 

demand-side energy efficiency serving 

as a basis for quantifying the amounts of 

generation reductions and consequent 

CO2 emission reductions that can be 

achieved while continuing to meet the 

demand for electricity services in a 

reliable and affordable manner. This 

alternate interpretation of the BSER is 

discussed in Section VI.E.7 below. 

5. Evaluation of Building Block 

Combinations Against the BSER Criteria 

a. Combination of Building Blocks 1 

and 2 

The EPA has considered whether a 

combination of building blocks 1 and 2 

would be the BSER. As described in 

Section VI.D above, we believe that such 

a combination is technically feasible 

and would be a ‘‘system of emission 

reduction’’ capable of achieving 

meaningful reductions in CO2 emissions 

from affected EGUs at a reasonable cost. 

The combination would also satisfy 

other BSER criteria. Nevertheless, we do 

not propose that this combination 

should be the BSER because the 

proposed combination of all four 

building blocks is capable of achieving 

greater reductions in CO2 emissions 

from affected EGUs at a lower cost. 

The EPA believes that both building 

blocks 1 and 2 individually satisfy the 

BSER criteria identified by the statute 

and the D.C. Circuit, with one possible 

concern, related to a ‘‘rebound effect,’’ 

noted earlier. That concern is the 

potential for the heat rate improvements 

in building block 1, if implemented in 

isolation, to make coal-fired steam EGUs 

more competitive compared to other 

EGUs and cause them to increase their 

generation, creating a ‘‘rebound effect’’ 

that would make building block 1 less 

effective at reducing CO2 emissions. As 

discussed above, building blocks 1 and 

2 each appear attractive or neutral with 

respect to each of the other BSER 

criteria. 

With respect to most of the BSER 

criteria, there is no reason to expect that 

the combination of building blocks 1 

and 2 would be evaluated differently 

from the individual building blocks. 

However, as noted earlier, the 

combination addresses the concern 

about building block 1 regarding a 

potential rebound effect, and in that 

important respect it performs better than 

building block 1 considered in isolation. 

The substitution of NGCC generation for 

generation from coal-fired and other 

steam EGUs ensures that generation 

from coal-fired EGUs, as a group, would 

not increase as a result of their 

improved variable costs, with the result 

that the reduction in CO2 emission rates 

of coal-fired EGUs brought about by heat 

rate improvements would not be offset 

by an increase in CO2 emissions due to 

increased generation from those EGUs. 

The combination of building blocks 

would therefore be capable of achieving 

greater reductions in CO2 emissions 

from affected sources than either 

building block in isolation. 

While achieving substantially greater 

emission reductions than building block 

1 alone, by reducing overall generation 

from coal-fired EGUs the combination of 

building blocks 1 and 2 also has the 

potential to raise the cost of the portion 

of the overall emission reductions 

achievable through heat rate 

improvements relative to the cost of 

those reductions if building block 1 

were implemented in isolation.218

However, the EPA believes that the cost 

of emission reductions achieved 

through heat rate improvements would 

remain reasonable for two reasons. First, 

as discussed in Section VI.C.1 above, 

the cost of CO2 emission reductions 

achievable through heat rate 

improvements is quite low, and that 

cost would remain reasonable even if it 

was substantially increased. Second, 

although under the combination of 

building blocks 1 and 2 the volume of 

coal-fired generation would decrease, 

that decrease is unlikely to be spread 

uniformly among all coal-fired EGUs. It 

is more likely that some coal-fired EGUs 

would decrease their generation slightly 

while others would decrease their 

generation by larger percentages or 

cease operations altogether. We would 

expect EGU owners to take these 

changes in EGU operating patterns into 

account when considering where to 

invest in heat rate improvements, with 

the result that there would be a 

tendency for such investments to be 

concentrated in EGUs whose generation 

output was expected to decrease the 


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219The analysis of the interactions among 

building blocks provided above for the combination 

of building blocks 1 and 2, indicating that the 

addition of building block 2 would mitigate the 

potential concern about a ‘‘rebound effect’’ if 

building block 1 were implemented in isolation, 

applies to the combination of all four building 

blocks as well; in fact, the addition of building 

blocks 3 and 4 would further mitigate that concern. 

The EPA believes that if implemented in 

combination, each of the four building blocks 

would achieve substantial reductions in CO2

emissions from affected EGUs at a reasonable cost. 

220Oxford Dictionary of English (3rd ed.) 

(published 2010, online version 2013), http://

www.oxfordreference.com.mutex.gmu.edu/view/

10.1093/acref/9780199571123.001.0001/acref9780199571123. 

least. This enlightened bias in spending 

on heat rate improvements—that is, 

focusing investments on EGUs where 

such improvements would have the 

largest impacts and produce the highest 

returns, given consideration of projected 

changes in dispatch patterns—would 

tend to mitigate any deterioration in the 

cost of CO2 emission reductions 

achievable through heat rate 

improvements. 

As noted above, the EPA invites 

comment on a potential BSER 

comprising building blocks 1 and 2, in 

light of the considerations that could 

support this approach. 

b. Combination of All Four Building 

Blocks 

The EPA’s proposed BSER is a 

combination of all four building blocks. 

For the reasons described below, and 

similar to each of the building blocks, 

the combination must be considered a 

‘‘system of emission reduction.’’ 

Moreover, as also discussed below, the 

combination qualifies as the ‘‘best’’ 

system that is ‘‘adequately 

demonstrated.’’ The combination is 

technically feasible; it is capable of 

achieving meaningful reductions in CO2

emissions from affected EGUs at a 

reasonable cost; it satisfies the other 

BSER criteria as well; and its 

components are well-established. The 

combination of all four building blocks 

would achieve greater CO2 emission 

reductions at a lower cost than the 

combination of building blocks 1 and 2 

described above, and would also 

perform better against other BSER 

criteria. We therefore propose to find 

the combination of all four building 

blocks to be the ‘‘best system of 

emission reduction . . . adequately 

demonstrated’’ for reducing CO 

emissions at affected EGUs.219

The assessments of the individual 

building blocks against the BSER 

criteria would generally apply in the 

same way to those building blocks when 

implemented as the combination of all 

four building blocks, with the same 

exceptions as discussed above with 

respect to the combination of building 

blocks 1 and 2 as well. However, the 

combination of all four building blocks 

would improve upon the combination of 

building blocks 1 and 2 in several 

respects. First, because of the potential 

of building blocks 3 and 4 to achieve 

additional CO2 reductions at reasonable 

costs, the broader combination would 

achieve greater CO2 emission reductions 

at a lower average cost. Second, by 

encompassing the increased low-and 

zero-carbon generation in building block 

3, the broader combination would 

reduce reliance on fossil fuels and 

improve fuel diversity. Third, by 

encompassing the increased demandside energy efficiency in building block 

4, the broader combination would 

reduce the amount of electricity that 

would need to be delivered over the 

electric grid, generally reducing 

pressure on the grid and thereby 

improving electricity system reliability. 

These considerations all support basing 

the BSER on the combination of all four 

building blocks. They also support 

basing the BSER, in the alternative, on 

the combination of building block 1 and 

reduced generation in the amounts 

facilitated by the remaining building 

blocks. 

As has been discussed in earlier 

portions of the preamble, the costs and 

energy impacts of each of the four 

building blocks individually are 

reasonable when viewed either at the 

individual source level or through the 

lens of the electricity system as a whole, 

a conclusion that holds for the 

combination of the building blocks as 

well. Moreover, the flexibility available 

to states and regulated entities to rely 

more extensively in their plans and 

strategies on whichever measures best 

suit their particular circumstances will 

further improve cost effectiveness. The 

analysis the EPA performed to assess 

the costs, benefits, and other impacts of 

the proposed goals reflects this 

compliance flexibility, along with 

transmission and pipeline capabilities 

and constraints, fuel market and 

electricity dispatch dynamics, and 

seasonal electricity load requirements. 

As described below in Section X, the 

results indicate that the proposed state 

goals (discussed in Section VII) are 

readily achievable with no adverse 

impacts on electricity system reliability, 

and that impacts on retail electricity 

prices are modest and fall within the 

range of price variability seen 

historically in response to changes in 

factors such as weather and fuel supply. 

Further, the costs tend to decline over 

time as states and regulated entities take 

advantage of the available flexibility and 

expand deployment of more costeffective measures (notably demandside energy efficiency). The EPA 

considers this analysis strong 

confirmation of the reasonableness of 

the costs of the measures in the four 

building blocks in combination as the 

best system of emission reduction. 

6. Additional Considerations Related to 

Inclusion of Building Blocks 2, 3, and 4 

as Part of the Basis Supporting the BSER 

In this section, we discuss additional 

reasons why the measures in building 

blocks 2, 3, and 4, individually and in 

combination, meet the requirements to 

be components of the BSER. In 

particular, we discuss why they meet 

the definition of a ‘‘system of emission 

reduction,’’ and we provide additional 

reasons why they are the ‘‘best’’ that is 

‘‘adequately demonstrated.’’ The 

interconnected nature of the electric 

system is an important part of our 

reasoning. 

a. ‘‘System of Emission Reduction’’ 

For the convenience of the reader, it 

is useful to reiterate the key CAA 

section 111 requirements: Section 

111(d)(1) requires that each state’s plan 

‘‘establish[] standards of performance 

for any existing source’’ for certain types 

of air pollutants; and section 111(a)(1) 

defines a ‘‘standard of performance’’ as 

‘‘a standard for emissions . . . which 

reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction . . . adequately 

demonstrated.’’ These provisions 

require that, in this rulemaking, the 

affected sources must be subject to 

emissions standards, but the basis for 

those standards—the ‘‘system of 

emission reduction’’—may be any 

method that reduces the affected 

sources’ emissions, as long as that 

method is a ‘‘system’’ that meets the 

criteria for being the ‘‘best’’ that is 

‘‘adequately demonstrated.’’ 

As discussed in the Legal 

Memorandum, the EPA is justified in 

adopting this interpretation under the 

first step of the framework for 

administrative agencies to construe 

statutes that the U.S. Supreme Court 

established in Chevron U.S.A. Inc. v. 

NRDC, 467 U.S. 837, 842–844 (1984) 

(Chevron), which we refer to as Chevron 

step 1. 

Specifically, the term ‘‘system,’’ 

which is not defined in the CAA, is 

broad: ‘‘A set of things working together 

as parts of a mechanism or 

interconnecting network.’’ 220 The 


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221CAA § 101(a)(3), (c). 

222For example, as discussed in the Legal 

Memorandum, CAA § 407(b)(2) requires the EPA to 

base the nitrogen oxides (NOX) emission limits for 

certain types of boilers ‘‘on the degree of reduction 

achievable through the retrofit application of the 

best system of continuous emission reduction . . . 

;’’ and further requires the EPA to revise previously 

promulgated emission limits for certain types of 

boilers ‘‘to be more stringent if the [EPA] 

determines that more effective low NOX burner 

technology is available.’’ (Emphasis added.) 

223CAA § 401(b), 404(f)–(g). 

224See Nordhaus R., Gutherz I., ‘‘Regulation of 

CO2 Emissions from Existing Power Plants Under 

§ 111(d) of the Clean Air Act: Program Design and 

Statutory Authority,’’ Environmental Law Reporter, 

44: 10366, 10384 (May 2014) (‘‘strong arguments 

for’’ interpreting ‘‘system’’ to include measures 

such as the addition of new zero-carbon generating 

capacity and increases in end-user energy 

efficiency); Sussman R., ‘‘Power Plant Regulation 

Under the Clean Air Act: A Breakthrough Moment 

for U.S. Climate Policy?’’ Virginia Environment Law 

Journal, 32:97, 119 (2014) (‘‘EPA would seem to 

have discretion to define ‘system’ to include any 

mix of strategies effective in reducing emissions.’’); 

Konschnik K., Peskoe A., ‘‘Efficiency Rules: The 

Case for End-Use Energy Efficiency Programs in the 

Section 111(d) Rule for Existing Power Plants,’’ 

Harvard Law School Environmental Law Program— 

Policy Initiative 4 (March 3, 2014) (EPA is 

authorized to ‘‘consider[ ] . . . the entire 

[electricity grid] system when setting performance 

standards.’’); Monast J., Profeta T., Pearson B., 

Doyle J., ‘‘Regulating Greenhouse Gas Emissions 

From Existing Sources: Section 111(d) and State 

Equivalency,’’ Environmental Law Reporter, 42: 

10206, 10209 (March 2012) (‘‘Demand-side energyefficiency programs and renewable energy 

generation may fit within the § 111 framework, 

however, because both reduce the utilization of 

power plant. . . . According to this reasoning, 

emission reductions are occurring within the source 

category, because of changes in generation at the 

power plant.’’). 

225Ceronsky M., Carbonell T., ‘‘Section 111(d) of 

the Clean Air Act: The Legal Foundation for Strong, 

Flexible & Cost-Effective Carbon Pollution 

Standards for Existing Power Plants,’’ 

Environmental Defense Fund, at 9 (Oct. 2013), 

available at http://www.edf.org/sites/default/files/

111-clean_air_act-strong_flexible_cost-effective_

carbon_pollution_standards_for_existing_power_

plants.pdf; Doniger D., ‘‘Questions and Answers on 

the EPA’s Legal Authority to Set ‘System Based’ 

Carbon Pollution Standards for Existing Power 

Plants under Clean Air Act Section 111(d),’’ NRDC 

[Natural Resources Defense Council] Issue Brief 

(Oct. 2013); ‘‘Comments of the Attorneys General of 

New York, California, Massachusetts, Connecticut, 

Delaware, Maine, Maryland, New Mexico, Oregon, 

Rhode Island, Vermont, Washington, and the 

District of Columbia on the Design of a Program to 

Reduce Carbon Pollution from Existing Power 

Plants’’ (Dec. 16, 2013). 

remaining provisions of the definition of 

‘‘standard of performance’’ do not 

include any constraints on the ‘‘set of 

things’’ that may constitute a ‘‘system of 

emission reduction.’’ Nor does the 

context in which ‘‘standard of 

performance’’ is found—the provisions 

of section 111(d)(1)—add constraints on 

the things that may constitute such a 

system. Rather, it is clear from these 

CAA provisions that anything that 

reduces the emissions of affected 

sources may be considered a ‘‘system of 

emission reduction’’ for those sources. 

For this reason, the measures in 

building blocks 2, 3, and 4 must be 

considered components of such a 

system. 

Even if these CAA provisions leave 

room for interpretation as to whether 

those measures must be considered 

components of such a system, the EPA’s 

interpretation that they do is reasonable. 

As discussed in the Legal 

Memorandum, the EPA is justified in 

adopting this interpretation under the 

second step of the Chevron framework, 

which we refer to as Chevron step 2. 

There are several reasons. In enacting 

the CAA, Congress established 

‘‘pollution prevention’’ as a ‘‘primary 

goal’’ of the Act, and described it as ‘‘the 

reduction or elimination, through any 

measures, of the amount of pollutants 

produced or created at the source.’’ 221

Building blocks 2, 3, and 4 are pollution 

prevention measures, and, in light of the 

importance of pollution prevention in 

the CAA, it is reasonable to interpret 

‘‘system of emission reduction’’ in 

section 111 to incorporate those 

measures. In addition, the breadth of 

‘‘system of emission reduction’’ is 

confirmed by contrasting it with other 

provisions in the CAA that prescribe 

specific types of controls as the basis for 

emission limits.222 Further support is 

found in Title IV of the CAA, in which 

Congress established the program that 

regulates fossil fuel-fired power plants 

to reduce their emissions of SO2 and 

NOX, the precursors to acid deposition. 

In designing Title IV, Congress 

recognized the integrated nature of the 

electricity sector and how that 

integration could be harnessed to reduce 

air pollutant emissions. In fact, Congress 

included provisions to encourage redispatch to lower-emitting sources, 

renewable energy, and demand-side 

energy efficiency, all of which are 

measures in those building blocks.223

All this supports the reasonableness of 

interpreting ‘‘system of emission 

reduction’’ in CAA section 111 to 

incorporate those measures. It should 

also be noted that a number of 

commentators in the private sector and 

academia have indicated support for 

interpreting the term, ‘‘system of 

emission reduction’’ to base the CAA 

section 111(d) standards of performance 

on measures such as re-dispatch, 

renewable energy, and demand-side 

energy efficiency.224 Some stakeholders 

have as well.225

b. ‘‘Best’’ System That Is ‘‘Adequately 

Demonstrated 

As described earlier with respect to 

the individual building blocks, the 

measures in each of building blocks 2, 

3, and 4 meet the criteria for the ‘‘best’’ 

system of emission reduction, and, 

generally for the same reasons, the three 

in combination do as well. 

In addition, the measures in building 

blocks 2, 3, and 4, individually and in 

combination, are ‘‘adequately 

demonstrated.’’ As discussed earlier, 

thanks to the integrated nature of the 

electricity system, they have long been 

relied on to reduce costs in general, 

assure reliability, and implement preexisting pollution control requirements 

in the least-cost manner. As also noted 

elsewhere in the preamble, and 

discussed in more detail in the 

following subsections, some utilities, 

states and regions are already relying on 

these measures for the specific purpose 

of reducing CO2 emissions from EGUs. 

(i) Actions by Affected EGUs 

Measures in building blocks 2, 3, and 

4 may be undertaken or invested in by 

the affected EGUs themselves, which 

supports that these measures are 

‘‘adequately demonstrated.’’ More 

specifically, the EPA believes that 

owners of units operating across a wide 

range of corporate, institutional and 

market structures (e.g., vertically 

integrated utilities in regulated markets, 

independent power producers, 

municipal utilities, and rural 

cooperatives) can take advantage of a 

broad range of reduction opportunities 

included in the building blocks. 

Because of the proposed lengthy 

planning period, owners can consider 

longer-term options such as 

implementing energy efficiency 

programs or replacement of older 

generating resources with more modern 

types of generation, as well as shorterterm options such as heat rate 

improvements and re-dispatch. Many 

companies, for example, already factor a 

carbon cost adder into their long-term 

planning decisions. 

Large vertically integrated utilities 

generally have options within all four 

building blocks. They tend to have large 

and, as a general matter, at least 

somewhat diverse generation fleets. For 

their higher-emitting units, they have 

opportunities to use measures that 

reduce the units’ CO2 emission rates, 

such as heat rate improvements, cofiring, or fuel switching. While this 

proposal preserves fuel diversity, with 

over 30 percent of projected 2030 

generation coming from coal and over 

30 percent from natural gas, even 

companies that have traditionally 

depended upon coal to supply the 

majority of their generation are 

diversifying their fleets, increasing their 


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226http://online.wsj.com/article/PR-;CO20140508-;915605.html. 

227For examples, see Large Public Power Council, 

Energy Efficiency Working Group, Second Annual 

Energy Efficiency Benchmarking Report (2013); 

https://www.nreca.coop/nreca-on-the-issues/

energy-operations/energy-efficiency/. 

228See, e.g., Guidance on SIP Credits for Emission 

Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures (Aug. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ 

ereseerem_gd.pdf; Incorporating Emerging and 

Voluntary Measures in a State Implementation Plan 

(SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/ 

memoranda/evm_ievm_g.pdf. 

229 DC Region 8-hour ozone SIP at 126, http:// 

www.mwcog.org/uploads/pub-documents/ 

9FhcXg20070525084306.pdf. 

230 Dallas/Ft. Worth, Texas 8-hour ozone SIP, 

http://www.gpo.gov/fdsys/pkg/FR-2008-08-15/pdf/ 

E8-18835.pdf. 

231CT 1997 8-hour ozone SIP Web site, http:// 

www.ct.gov/deep/cwp/ 

view.asp?a=2684&q=385886&depNav_GID=1619 

(see Attainment Demonstration TSD, Chapter 8 at 

31, http://www.ct.gov/deep/lib/deep/air/ 

regulations/proposed_and_reports/section_8.pdf). 

232Roadmap for Incorporating EE/RE Policies and 

Programs into SIPs/TIPs (July 2012), http://epa.gov/ 

airquality/eere/manual.html. 

233States’ Perspectives on EPA’s Roadmap to 

Incorporate Energy Efficiency/Renewable Energy in 

NAAQS State Implementation Plans: Three Case 

Studies, Final Report to the U.S. Environmental 

Protection Agency (Dec. 2013), http:// 

www.nescaum.org/documents/nescaum-final-reptto-epa-ee-in-naaqs-sip-roadmap-case-studies20140522.pdf. 

opportunities for re-dispatch.226 Within 

the 5-to-15-year planning horizon 

established in this proposal to begin in 

June 2015, most of these companies are 

likely to be investing in new generation 

and can consider options such as 

increased reliance on new renewable 

generating capacity. They also run 

energy efficiency programs for their 

customers. 

Municipal utilities and rural 

cooperatives that own generating asset 

portfolios also have multiple options for 

reducing CO2 emissions, particularly 

generation and transmission 

cooperatives and larger municipal 

utilities. They can implement unitspecific improvements, re-dispatch to 

lower emitting resources, employ energy 

efficiency and renewable energy 

strategies, and explore longer-term 

capacity planning strategies. For 

cooperatives and municipal utilities 

with smaller fleets, re-dispatching 

among their own units may not provide 

as many opportunities, particularly in 

the short term. But because of the timing 

flexibility in the guidelines, these 

owners can use both short-term dispatch 

strategies and longer-term capacity 

planning strategies to reduce GHG 

emissions, and in many cases financing 

is available at tax-advantaged or 

subsidized rates. At the same time, in 

formulating their plans, states will be in 

a position to recognize the distinctive 

attributes of smaller utilities—and, of 

course, may consider participating in 

integrated multi-state compliance 

strategies to increase the flexibility and 

cost-saving opportunities that would be 

available to the covered EGUs. 

Some stakeholders have expressed 

concerns that municipal utilities and 

rural cooperatives can face other 

challenges as well. According to these 

stakeholders, in deregulated areas, even 

though these utilities may be fully 

vertically integrated entities, they may 

not have as much flexibility to control 

dispatch because they are operating in 

a competitive market, where they can be 

in a position in which they need to 

operate if called upon. Even in this case, 

the timing flexibility of the rule allows 

them to consider longer-term capacity 

planning strategies. These can include 

building or contracting for electric 

supply from lower-emitting sources, use 

of distributed renewable technologies, 

and use of demand-side energy 

efficiency measures. There are a number 

of municipal utilities and rural 

cooperatives that are already 

aggressively pursuing such strategies.227

Nevertheless, in recognition of 

stakeholders’ expressed concerns, we 

invite comment on whether there are 

special considerations affecting small 

rural cooperative or municipal utilities 

that might merit adjustments to this 

proposal, and if so, possible adjustments 

that should be considered. 

Independent power producers (IPPs) 

may also face unique challenges but 

nevertheless have options. Companies 

with coal-fired EGUs can implement 

efficiency improvements as well as 

other unit-level compliance options 

such as co-firing or fuel switching. 

While these types of companies do not 

use the integrated resource planning 

process that many vertically integrated 

utilities use, they still undertake longterm business planning and as a result 

are in a position to consider different 

long-term strategies related to their 

generating assets. Many IPPs are 

actively developing renewable 

generating capacity and natural gas-fired 

generating capacity. IPP owners could 

also fund demand-side energy efficiency 

programs and document the resulting 

electricity savings. 

(ii) Actions by States 

Another reason why the measures in 

building blocks 2, 3, and 4 are 

‘‘adequately demonstrated’’ is that states 

may adopt them and, in fact, many 

states have already adopted many of 

them. 

For example, several states have 

already adopted renewable energy (RE) 

and demand-side energy efficiency (EE) 

measures in their CAA section 110 state 

implementation plans (SIPs) for 

attaining and maintaining the national 

ambient air quality standards (NAAQS). 

The EPA has provided initial guidance 

for states to do so.228 Some state air 

agencies did so for their 1997 8-hour 

ozone NAAQS SIPs that were due in 

2007; for example, Washington, DC, 

included the purchase of wind power 

and the installation of LED traffic 

lights 229; Dallas, Texas included 

efficiency measures from the Texas 

Emissions Reduction Program 

(TERP) 230; and Connecticut included 

projects such as high efficiency air 

conditioners, compact fluorescent 

lighting, combined heat and power 

(CHP), and solar photovoltaic 

installations.231 Since that time, many 

states have adopted legislative mandates 

for energy efficiency or renewable 

energy, and states have expressed 

interest in including EE/RE policies and 

programs in upcoming NAAQS SIPs. 

The EPA has provided additional 

guidance 232 and has partnered with the 

Northeast States for Coordinated Air 

Use Management (NESCAUM) and three 

states (Maryland, Massachusetts, and 

New York) to identify opportunities for 

including EE/RE in a NAAQS SIP and 

to provide real-world examples and 

lessons learned through those states’ 

case studies.233

It should be recognized that each 

state’s electric utility sector operates 

under distinctive conditions and 

circumstances. The EPA’s proposal 

ensures that states retain flexibility to 

craft standards of performance that can 

accommodate characteristics including 

fuel sources, types of EGU owners 

within a state (e.g., investor-owned, 

municipal, and cooperative utilities, 

and independent power producers), and 

regulatory structure (e.g., regulated or 

restructured). States can tailor their 

regulatory mechanisms to recognize 

differences, for example by creating 

budgets on a company-wide basis or 

using market-based mechanisms such as 

mass-based trading systems, to ensure 

that requirements are achievable. 

The proposal also recognizes that 

states have different resource bases and 

energy policies in place, and these 

differences are taken into account in the 

state goal-setting and computation 

process. For instance, while the EPA’s 

BSER assumptions consider re-dispatch 

to NGCC units, they do not consider redispatch beyond the NGCC capacity 

already existing in a state. In that way, 

the proposal does not presume that 


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234See the discussions of California California 

Global Warming Solutions Act and RGGI above in 

this section and elsewhere in the preamble. 

235Across all markets, at the federal level, FERC 

and NERC create and oversee standards for 

reliability. NERC works with electric reliability 

councils and control areas that comprise all types 

of utilities and system operators to ensure that 

adequate generation is available. 236http://www.isorto.org/Documents/Report/ 

20140128_IRCProposal-ReliabilitySafetyValveRegionalComplianceMeasurement_EPAC02Rule.pdf. 

states with limited natural gas 

generation or infrastructure will have to 

develop those resources. 

Furthermore, while the BSER reflects 

best practices for both renewables and 

energy efficiency, it also recognizes that 

some states have made more progress 

than others in these areas. The BSER 

allows time for states to ramp up to 

greater levels of energy efficiency and 

use and development of renewable 

energy resources, should they choose 

those approaches. With respect to 

renewable energy, the proposal also 

recognizes that different areas of the 

country have different resource bases 

and does not presume that a uniform 

level of penetration of renewable 

generation is appropriate for every state. 

The features provided in this proposal 

to ensure policy flexibility can be used 

by all states to address their unique 

circumstances. In a regulated state, if a 

company’s compliance strategies 

included reducing generation at higheremitting EGUs, it would work through 

its state’s integrated planning process to 

ensure that adequate generation was 

available through a combination of all 

four building blocks. Cost recovery, and 

cost oversight, can be achieved through 

rate cases before state regulators. In a 

restructured state, even if affected 

companies responded to the guidelines 

by reducing generation without 

themselves replacing that generation, 

the electricity markets that have 

developed would react to ensure the 

availability of replacement generation. 

Other companies would see 

opportunities to build or ramp up 

existing lower-emitting generation, and 

in some markets that treat demand-side 

resources on par with supply side 

resources, energy service companies 

would likely see opportunities. Further, 

state regulators can continue to play an 

important role in restructured states as 

well, authorizing or reviewing both 

renewable energy procurement and 

demand-side energy efficiency 

programs. In all types of market 

structures, large energy users might 

independently see additional energy 

efficiency opportunities or 

opportunities for self-generation using 

options such as combined heat and 

power, solar, or power purchase 

agreements, and states can structure 

their plans to allow the CO2 reductions 

achieved at affected EGUs through such 

actions to assist in reaching compliance. 

As discussed in earlier portions of this 

section and elsewhere in the preamble, 

each of the building blocks is already 

being widely implemented, is consistent 

with industry trends, and consists of 

CO2 reduction methods already widely 

accepted in the eyes of various 

stakeholders, as was clear from views 

expressed in our outreach process. 

Moreover, there are mechanisms 

through which states could require 

measures from any of the building 

blocks in state plans. In fact, the state 

plan formulation process through which 

CAA section 111(d) is implemented 

reinforces the determination that these 

measures are components of the BSER. 

For example, states would have 

authority to impose measures such as 

best practices for operation and 

maintenance of EGUs, dispatch limits, 

renewable energy resource 

requirements, and demand-side energy 

efficiency requirements. States also 

would have authority to establish 

requirements that change the relative 

costs of generation from more carbonintensive and less carbon-intensive 

EGUs, for example by creating emission 

allowance systems that cause market 

participants and system operators to 

take account of CO2 emission rates as an 

element of variable operating costs. 

Such an approach can encourage 

measures from all of the building blocks 

simultaneously. As noted elsewhere in 

the preamble, many states have already 

pursued one or more of these 

approaches.234

It also should be noted that during the 

public outreach sessions, stakeholders 

generally recommended that state plans 

be authorized to rely on, and that 

affected sources be authorized to 

implement, re-dispatch, renewable 

energy measures, and demand-side 

energy efficiency measures in order to 

meet states’ and sources’ emission 

reduction obligations. The EPA agrees 

that state plans may include these 

measures, at least under certain 

circumstances, as discussed in Section 

VIII, and that sources may rely on them 

to achieve required reductions. It is 

clear that these types of measures are 

well-accepted by the stakeholders as 

means to reduce emissions from affected 

sources. The fact that state plans and 

sources would be expected to use these 

types of measures to reduce emissions 

supports the view that these measures 

are part of a ‘‘system of emission 

reduction’’ for those sources that the 

EPA may evaluate against the 

appropriate criteria to determine 

whether they comprise the ‘‘best system 

of emission reduction . . . adequately 

demonstrated.’’ 

(iii) Regional Organizations 

Another reason why the measures in 

building blocks 2, 3, and 4 are 

‘‘adequately demonstrated’’ is that they 

can be accommodated through the 

existing regional components of the 

electricity system. 

On the regional level, ISO/RTOs 

control dispatch and are responsible for 

reliable operation of the bulk power 

system.235 They can seek solutions, 

such as capacity markets and 

transmission upgrades, to preserve 

resource adequacy and ensure the 

continued reliable operation of the grid. 

For this proposal, the ISO/RTO Council 

has already submitted a set of 

recommendations they believe can help 

balance the needs of lower emissions, 

economic dispatch, and reliability, 

which is discussed in greater detail in 

Section VIII.F.7 of this proposal.236 For 

areas of the country that are not covered 

by an ISO/RTO, there are regional 

groups, such as ColumbiaGrid, Northern 

Tier Transmission Group and 

WestConnect in the west, and system 

operators such as Southern Company in 

the southeast, that can provide these 

functions. In shifting to lower-emitting 

units, grid operators across the country 

factor environmental costs into their 

economic dispatch through a variety of 

mechanisms, including allowance costs, 

variable costs associated with operating 

environmental controls, and operating 

limits for high-emitting units. 

(iv) Concerns From Stakeholders; 

Solicitation of Comment 

We note that some stakeholders have 

argued that CAA section 111(a)(1) does 

not authorize the EPA to identify redispatch, low- or zero-emitting 

generation, or demand-side energy 

efficiency measures (building blocks 2, 

3, and 4) as components of the ‘‘best 

system of emission reduction . . . 

adequately demonstrated.’’ According to 

these stakeholders, as a legal matter, the 

BSER is limited to measures that may be 

undertaken at the affected units, and not 

measures that are beyond the affected 

units; the measures in building blocks 2, 

3, and 4 are ‘‘beyond-the-unit’’ or 

‘‘beyond-the-fenceline’’ measures 

because they are implemented outside 

of the affected units and outside their 

control; and as a result, those measures 

cannot be considered components of the 

BSER. 

We welcome comment on this issue. 

As discussed above, we propose that the 


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237Commenters have critiqued this ‘‘at-the-unit’’ 

and ‘‘beyond-the-unit’’ distinction as follows: 

There is an argument that the at-the-unit/beyondthe-unit distinction is not a meaningful one. 

Specifically, it could be argued that the distinction 

between at-the-unit and beyond-the-unit measures 

is largely artificial, because all of the emission 

reductions under consideration—whether from atthe-unit measures (e.g., fuel-switching or efficiency 

upgrades) or from beyond-the-unit measures—are, 

in fact, emission reductions at or from electric 

generating units on the interconnected electric grid. 

For example, neither the addition of renewable 

generation nor the reduction of end-user demand 

directly reduces atmospheric emission of CO2; 

rather these measures permit fossil EGUs to reduce 

their own output and emissions. It can be argued 

that all of the systems of emission reduction here 

contemplated—whether they involve end-use 

energy efficiency, displacing high-emission 

generation with lower emission generation, fuelswitching, heat-rate improvements, etc.—are 

effectively at-the-unit measures that ultimately 

reduce emissions solely from regulated EGUs. If 

energy-efficiency programs, added renewable 

energy, and redispatch from higher emitting 

facilities to lower emitting facilities are viewed as 

at-the-unit systems of emission reduction, the atthe-unit/beyond-the-unit distinction arguably 

becomes irrelevant—at least from a legal 

perspective. Rather, the real issue may come down 

to whether § 111(d) authorizes the EPA to require 

EGUs to curtail their output of electricity as a 

means of complying with the rule. 

Nordhaus R., Gutherz I., ‘‘Regulation of CO2

Emissions from Existing Power Plants Under 

§ 111(d) of the Clean Air Act: Program Design and 

Statutory Authority,’’ Environmental Law Reporter, 

44: 10366, 10383 n. 133 (May 2014). 

238For this reason, under a Chevron step 1 

interpretation, ‘‘system of emission reduction’’ 

includes reduced generation. 

239For these reasons, under a Chevron step 2 

interpretation, ‘‘system of emission reduction’’ 

includes reduced generation. 

240See CAA section 110(g) (authorizing 

temporary emergency suspensions of SIP revisions 

if needed to prevent the closing of a source of air 

pollution), enacted as CAA section 110(f) in the 

1970 CAA Amendments; 116 Cong. Rec. 42384 

(Dec. 18, 1970), reprinted in Congressional Research 

Service, A Legislative History of the Clean Air Act 

Amendments of 1970, vol. 1, at 132–33 (1974) 

(statement of Sen. Muskie) (discussing criteria for 

sources to receive compliance date extensions). 

Sen. Muskie added that the emission standards set 

by the EPA for hazardous air pollutants ‘‘could 

include emission standards which allowed for no 

measureable emissions,’’ id., which further suggests 

that, as a practical matter, the standards could 

result in reduced production. 

241See, e.g., Consent Decree at 18, United States 

v. Wis. Power & Light Co., No. 13–cv–266 (W.D. 

Wis. filed Apr. 22, 2013), available at http:// 

www2.epa.gov/sites/production/files/documents/ 

wisconsinpower-cd.pdf. 

242 63 FR 57356 (Oct. 27, 1998). 

243 70 FR 25162 (May 12, 2005). 

provisions of CAA section 111 do not by 

their terms preclude the BSER from 

including those types of measures. In 

addition, as noted above, under our 

proposed approach, affected sources 

may themselves implement the 

measures included in building blocks 2, 

3, and 4, so that those measures are 

within their control with the result of 

their application being emissions 

reductions at affected EGUs. Moreover, 

under our alternative approach, the 

‘‘system of emission reduction’’ 

includes reductions in utilization at the 

affected sources themselves.237 It should 

also be noted that, as discussed above, 

the re-dispatch measures in building 

block 2 are limited to affected sources. 

Thus, the proposed approach and 

alternative described above respond to 

these stakeholder concerns. 

7. Alternate Approach to the Best 

System of Emission Reduction 

As an alternative to the approach 

described above for determining the 

‘‘best system of emission reduction . . . 

adequately demonstrated,’’ the ‘‘system 

of emission reduction’’ may be 

identified as including, in addition to 

building block 1, the reduction of 

affected fossil fuel-fired EGUs’ mass 

emissions achievable through 

reductions in generation of specified 

amounts from those EGUs. Under this 

approach, the measures in building 

blocks 2, 3, and 4 would not be 

components of the system of emission 

reduction but instead would serve as 

bases for quantifying the reduced 

generation (and therefore emissions) at 

affected EGUs, and assuring that the 

amount of reduced generation meets the 

criteria for the ‘‘best’’ system that is 

‘‘adequately demonstrated’’ because, 

among other things, the reduced 

generation can be achieved while the 

demand for electricity services can 

continue to be met in a reliable and 

affordable manner. Specifically, the 

amount of generation from the increased 

utilization of NGCC units would 

determine a portion of the amount of the 

generation reduction component of the 

BSER for affected fossil fuel-fired steam 

EGUs, and the amount of generation 

from the use of expanded low- and zerocarbon generating capacity that could be 

provided, along with the amount of 

generation from fossil fuel-fired EGUs 

that could be avoided through the 

promotion of demand-side energy 

efficiency, would determine a portion of 

the amount of the generation reduction 

component of the BSER for all affected 

EGUs. 

Reduced generation is encompassed 

by the terms of the phrase ‘‘system of 

emission reduction’’ in CAA section 

111(a)(1), as a matter of Chevron step 1, 

because, in accordance with the abovediscussed definition of ‘‘system,’’ 

reduced generation is a ‘‘set of things’’— 

which include reduced use of 

generating equipment and therefore 

reduced fuel input—that the affected 

source may take to reduce its CO2

emissions.238 If that phrase is not 

considered clear by its terms, then, 

under Chevron step 2, it may reasonably 

be interpreted to include reduced 

generation.239 As discussed in the Legal 

Memorandum, the legislative history of 

the 1970 CAA Amendments indicates 

that Congress recognized that emitting 

sources could comply with pollution 

control requirements by reducing 

production, including retiring.240 As 

also noted in the Legal Memorandum, 

examples of reduced utilization as a 

means of reducing emissions are found 

in settlement agreements between the 

EPA and fossil fuel-fired EGUs to 

resolve alleged violations of the CAA 

new source review (NSR) 

requirements.241

Reduction of, or limitation on, the 

amount of generation is already a wellestablished means of reducing 

emissions of pollutants in the electric 

sector, notwithstanding the fact that as 

a practical matter, some facilities may 

have to operate, or remain available, to 

ensure system reliability. For example, 

reduced generation by higher-emitting 

sources is one of the compliance options 

available to, and used by, EGUs to 

comply with the Clean Air Act acid rain 

program in CAA title IV, as well as the 

transport rules that we refer to as the 

NOX SIP Call 242 and the Clean Air 

Interstate Rule (CAIR).243 Reduction in 

generation is also a possible means by 

which an EGU can achieve compliance 

with its requirements under RGGI. 

Reduced generation in specified 

amounts is part of the ‘‘best’’ system of 

emission reduction that is ‘‘adequately 

demonstrated.’’ Reduced generation is 

technically feasible because of a 

source’s ability to limit its own 

operations. In addition, the amounts of 

generation and emission reductions may 

be determined with precision through 

the application of building block 2, 3, 

and 4 measures for increased generation 

from low- or zero-emitting sources and 

increased demand-side energy 

efficiency, which, in turn, ensure the 

reliability of the electricity grid and the 

affordability of electricity to businesses 

and consumers. 

Because of the availability of the 

measures in building blocks 2, 3, and 4, 

the proposed levels of reduced 

generation are of reasonable cost for the 

affected source category and the 

nationwide electricity system, do not 

jeopardize reliability, result in an 

important amount of emission 

reductions, are consistent with current 

trends in the electricity sector, and 

promote the development and 

implementation of technology that is 

important for continued emissions 

reductions. All these results come about 

because the operation of the electrical 


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244 It should be noted that in light of the low 

current and projected near term prices for natural 

gas, market forces may lead investors to choose to 

build new NGCC units, rather than new renewable 

resources. This result would not call into question 

the technical feasibility of a BSER that included 

reductions in fossil fuel-fired generation by the 

amount of a specified amount of new renewable 

resources. This is because under these 

circumstances, the fossil fuel-fired generators could 

still reduce their generation without causing 

reliability or other problems in the electric power 

system. 

245The nuclear generating capacity reflected in 

building block 3 is already in operation or under 

construction. 

246Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. 

Cir. 1981). 

grid through integrated generation, 

transmission, and distribution networks 

creates fungibility for electricity and 

electricity services, which allows 

decreases in generation at affected fossil 

fuel-fired steam EGUs to be replaced by 

increases in generation at affected NGCC 

units (building block 2) and allows 

decreases in generation at all affected 

EGUs to be replaced by increased 

generation at low- or zero-carbon EGUs 

(building block 3) or by decreased 

demand (building block 4). Further, this 

fungibility increases over longer 

timeframes with the opportunity to 

invest in infrastructure improvements, 

and as noted elsewhere, this proposal 

provides an extended state plan and 

source compliance horizon. These 

characteristics of the integrated 

electricity system assure that reduced 

generation in specified amounts meets 

the criteria to qualify as part of the 

‘‘best’’ system of emission reduction. 

Reduced generation in those amounts 

is also ‘‘adequately demonstrated.’’ As 

noted above, the measures in building 

blocks 2, 3, and 4 are already in 

widespread use in the industry. At the 

levels proposed, they have the technical 

capability to substitute for reduced 

generation at some or all affected EGUs 

at reasonable cost. The NGCC capacity 

necessary to accomplish the levels of 

generation reduction proposed for 

building block 2 is already in operation 

or under construction. Moreover, it is 

reasonable to expect that the 

incremental resources reflected in 

building blocks 3 and 4 will develop at 

the levels requisite to ensure an 

adequate and reliable supply of 

electricity at the same time that affected 

EGUs may choose or be required to 

reduce their CO2 emissions by means of 

reducing their utilization. There are 

several reasons for this. First, the 

affected sources themselves could invest 

in new renewable energy resources and 

demand-side energy efficiency, as 

discussed above.244 Second, the states, 

as part of their plans, have mechanisms 

available to put these substitutes in 

place: They could establish 

requirements or incentives that would 

result in new renewable energy and 

demand-side energy efficiency 

programs, as also discussed above.245

Third, as also discussed above, regional 

entities in the electricity system can 

accommodate these substitutes. 

Most broadly, with respect to the 

measures in building blocks 2, 3, and 4, 

provided there is sufficient lead time for 

planning, mechanisms are in place in 

both regulated and deregulated 

electricity markets to assure that 

substitute generation will become 

available and/or steps to reduce demand 

will be taken to compensate for reduced 

generation by affected EGUs. These 

mechanisms are based on, among other 

things, the integrated nature of the 

electricity system coupled with the 

availability of capacity in existing NGCC 

units, the growing institutional capacity 

of entities that develop renewable 

energy and demand-side energy 

efficiency resources, and the ability of 

system operators and state regulators to 

incentivize further development of 

those resources. 

The EPA solicits comment on whether 

measures in addition to those in 

building blocks 2, 3, and 4 could 

support the showing that reduced 

utilization is ‘‘adequately 

demonstrated,’’ including additional 

NGCC capacity that may be built in the 

future, as discussed in Section VI.C.5.c 

above. 

8. The EPA’s Discretion in Applying the 

Criteria for the Best System of Emission 

Reduction 

As discussed above, each of the 

approaches to determining the ‘‘best 

system of emission reduction . . . 

adequately demonstrated’’ entails 

applying the criteria described in the 

D.C. Circuit case law for evaluating the 

BSER. It should be emphasized that 

under the case law, the EPA has 

significant discretion in weighing the 

different criteria, and may weigh them 

differently in different rulemakings. 

For the present proposal, the EPA is 

heavily weighting three criteria in 

particular: The amount of emission 

reductions, the cost of achieving those 

reductions, and the promotion of 

technology implementation—while also 

noting that the proposed BSER 

determination readily meets the other 

criteria as well. The EPA considers it 

especially important in this rulemaking, 

while ensuring that electricity system 

reliability is preserved and that costs are 

not unreasonable, to achieve a 

significant amount of emissions 

reductions in response to the urgency 

and the magnitude of the need to 

mitigate climate change. The EPA 

discusses this above in the sections 

concerning the scientific background for 

this rulemaking. The EPA also considers 

it especially important for the present 

proposal that the overall costs of 

achieving the emission reductions 

should be reasonable. Costs can be 

minimized through the flexibility to 

choose from a broad range of CO2

emission reduction measures, as is 

provided in the portion of this proposal 

addressing state plans, and a similarly 

broad range of emission reduction 

measures, represented by the four 

building blocks discussed above, should 

serve as the basis supporting the BSER. 

Finally, the EPA also considers it 

especially important for the present 

proposal to promote technological 

innovation and development of, in 

particular, the measures in building 

blocks 3 and 4 (to reiterate, low- or zerocarbon electricity generation and 

demand-side energy efficiency, 

respectively). Promoting innovation in, 

and market penetration of, these 

technologies and practices is critical to 

making the substantial reductions in 

emissions that will be required during 

the next few decades to reduce the risks 

to public health and welfare and our 

economic well-being of dangerous 

climate change. 

In addition, in this rulemaking, the 

EPA is determining the BSER in a 

manner that is consistent with, and that 

provides further impetus for, current 

trends in the nation’s electricity system 

that offer promise to reduce the carbon 

intensity of the system over the nearand long-term, while maintaining 

reliability and affordability. This 

approach is consistent with the case 

law, which authorizes the EPA to 

determine BSER by ‘‘balanc[ing] longterm national and regional impacts,’’ 

and by ‘‘using a long-term lens with a 

broad focus on future costs, 

environmental and energy effects of 

different technological 

systems. . . .’’ 246

9. State-Wide Application of the BSER; 

Appropriateness of Standards of 

Performance 

An important aspect of the BSER for 

affected EGUs is that the EPA is 

proposing to apply it on a statewide 

basis. The statewide approach also 

underlies the required emission 

performance level, which is based on 

the application of the BSER to a state’s 

affected EGUs, and which the suite of 

measures in the state plan, including the 

emission standards for the affected 


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247See Oxford Dictionary of English (3rd ed. 2010 

(online version 2013)) (defining ‘‘reflect’’ as, among 

other things, ‘‘embody or represent (something) in 

a faithful or appropriate way’’). 

EGUs, must achieve overall. The state 

has flexibility in assigning the emission 

performance obligations to its affected 

EGUs, in the form of standards of 

performance—and, for the portfolio 

approach, in imposing requirements on 

other entities—as long as, again, the 

required emission performance level is 

met. 

This state-wide approach both 

harnesses the efficiencies of emission 

reduction opportunities in the 

interconnected electricity system and is 

fully consistent with the principles of 

federalism that underlie the Clean Air 

Act generally and CAA section 111(d) 

particularly. That is, this provision 

achieves the emission performance 

requirements through the vehicle of a 

state plan, and provides each state 

significant flexibility to take local 

circumstances and state policy goals 

into account in determining how to 

reduce emissions from its affected 

sources, as long as the plan meets 

minimum federal requirements. 

In this subsection, we describe how 

this approach, and the standards of 

performance for the affected EGUs that 

the states will establish through the 

process we describe, are consistent with 

the CAA section 111(d)(1) and (a)(1) 

provisions. 

For convenience, we set out the 

requirements of CAA section 111(d)(1) 

and (a)(1) here: Under CAA section 

111(d)(1), the state must adopt a plan 

that ‘‘establishes standards of 

performance for any existing source.’’ 

Under CAA section 111(a)(1), a 

‘‘standard of performance’’ is a 

‘‘standard for emissions . . . which 

reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction . . . adequately 

demonstrated.’’ The EPA proposes to 

interpret these provisions as set forth in 

this sub-section. 

The first step is for the EPA to 

determine the ‘‘best system of emission 

reduction . . . adequately 

demonstrated.’’ As discussed at length 

elsewhere, the EPA is proposing two 

alternative BSER. The first is the 

measures in building blocks 1 through 

4 combined. This includes operational 

improvements and equipment upgrades 

that the coal-fired steam EGUs in the 

state may undertake to improve their 

heat rate by, on average, six percent and 

increases in, or retention of, zero- or 

low-emitting generation, as well as 

measures to reduce demand for 

generation, all of which, taken together, 

displace, or avoid the need for, 

generation from the affected EGUs. This 

BSER is a set of measures that impacts 

affected EGUs as a group. The 

alternative approach to BSER is building 

block 1 combined with reduced 

utilization from the affected EGUs in the 

state as a group, in the amounts that can 

be replaced by an increase in, or 

retention of, zero- or low-emitting 

generation, as well as reduced demand 

for generation. 

After determining the BSER, the EPA 

then applies the BSER to each state’s 

affected EGUs, on a state-wide basis. 

Building block 1 is applied to the coalfired steam EGUs on a statewide basis; 

building block 2 is applied to increase 

the generation of the NGCC units in the 

state up to certain amounts, and 

decrease the amount of generation from 

steam EGUs accordingly; and the 

measures in building blocks 3 and 4 are 

applied to reduce, or avoid, generation 

from all affected EGUs on a state-wide 

basis. Under the alternative formulation 

of the BSER, the total amount of 

reduced generation from the affected 

EGUs in the state, associated with the 

measures in building blocks 2, 3, and 4, 

is determined on the basis of each 

state’s affected EGUs as a group. 

This statewide approach to applying 

the BSER is consistent with the CAA 

section 111(a)(1) definition of ‘‘standard 

of performance,’’ which, as quoted 

above, refers to ‘‘the application of the 

[BSER],’’ for the purpose of determining 

‘‘the degree of emission limitation 

achievable,’’ but does not otherwise 

constrain how the BSER is to be 

applied. 

As a result, the EPA may apply the 

BSER to all of the affected EGUs in the 

state as a group. Similarly, the 

implementing regulations give the EPA 

broad discretion to identify the group of 

sources to which the BSER is applied. 

The regulations provide that the EPA 

‘‘will specify different emission 

guidelines or compliance times or both 

for different sizes, types, and classes of 

designated facilities when costs of 

control, physical limitations, 

geographical location, or similar factors 

make subcategorization appropriate.’’ 

Applying the BSER to the affected EGUs 

in each state as a group is appropriate, 

and therefore is consistent with these 

regulations. 

As part of applying the BSER, the 

EPA, to return to provisions of CAA 

section 111(a)(1), calculates the 

‘‘emission limitation achievable through 

the application of the [BSER].’’ In this 

rulemaking, we refer to this amount as 

the state goal. As noted, the EPA 

expresses the state goal in the emission 

guidelines as an emission rate. 

The state must develop a state plan 

that achieves the state goal, either in the 

form of an emission rate, as specified for 

the state in the emission guidelines, or 

a translated mass-based version of the 

rate-based goal. We refer to the state 

goal, in the form used by the state as the 

foundation of its plan, as the required 

emission performance level. 

As part of its state plan, the state must 

establish ‘‘standards of performance’’ for 

its affected EGUs. To do so, the state 

may consider the measures the EPA 

identified as part of the BSER or other 

measures that reduce emissions from 

the affected EGUs. Moreover, the state 

has the flexibility to establish emission 

standards in the degree of stringency 

that the state considers appropriate. The 

primary limitation on the state’s 

flexibility is that the emission standards 

applied to all of the state’s affected 

EGUs—and, in the case of states that 

adopt the portfolio approach, the 

requirements imposed on other affected 

entities—taken as a whole, must be 

demonstrated to achieve the required 

emission performance level. In addition, 

the state may make the emission 

standards for any of its affected EGUs 

sufficiently stringent, so that the 

standards and any requirements 

imposed on other affected entities (if 

relevant), taken as a whole, achieve a 

level of emission performance that is 

better than the required emission 

performance level. See CAA section 

116, 40 CFR 60.24(g). 

Under these circumstances—that the 

emission standards that the state 

establishes for its affected EGUs and any 

other requirements for the other affected 

entities, as relevant, taken together, are 

at least as stringent as necessary to 

achieve the required emission 

performance level for the state’s affected 

EGUs—each emission standard that the 

state adopts for each of its affected EGUs 

will meet the definition of a ‘‘standard 

of performance’’ under CAA section 

111(a)(1). Specifically, the ‘‘standard of 

performance’’ for each source will 

constitute, to return to the provisions of 

CAA section 111(a)(1), ‘‘a standard for 

emissions which reflects [that is, 

embodies, or represents] 247 the degree 

[that is, the portion] of emission 

limitation achievable through the 

application of the [BSER]’’ [that is, as 

noted above, the required emission 

performance level for all affected 

sources in a state]. That ‘‘degree’’ or 

portion of the required emission 

performance level is, in effect, the 

portion of the state’s obligation to limit 

its affected sources’ emissions that the 

state has assigned to each particular 

affected source. An emission standard 


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248The EPA’s approach may also be characterized 

as (i) determining the BSER for the affected EGUs, 

(ii) establishing as the emission guideline the 

standard for emissions that the affected EGUs in the 

state can achieve on average through the 

application of the BSER, and (iii) as part of the 

emission guideline, authorizing each state to 

establish as the applicable standard for each 

affected EGU, the standard that the state considers 

appropriate and that when totaled with the 

standards established for the other EGUs (and as 

may be adjusted to account for the portfolio 

approach, if that approach is adopted by the state) 

is at least as stringent as the average standard in the 

emission guideline. As noted in the accompanying 

text, a state has many ways to establish standards 

that meet the CAA requirements, including, for 

example, following the BSER or authorizing 

emission rate averaging or trading. 

249However, as noted, we are not soliciting 

comment on issues that were resolved by the 

implementing regulations. 

250As described below, the emission rate goals 

include adjustments to incorporate the potential 

effects of emission reduction measures that address 

power sector CO2 emissions primarily by reducing 

the amount of electricity produced at a state’s 

affected EGUs (associated with, for example, 

increasing the amount of new low- or zero-carbon 

generating capacity or increasing demand-side 

energy efficiency) rather than by reducing their CO2

emission rates per unit of energy output produced. 

251A method for translating from a rate-based 

goal to a mass-based goal is discussed in the 

Projecting CO2 Emission Performance in State Plans 

TSD. 

meets this definition of the term 

‘‘standard of performance’’ regardless of 

whether it is part of a plan that adopts 

the portfolio approach (in which case, 

the standard will reflect a relatively 

smaller part of the emission 

performance level) or one that imposes 

the plan’s emission limitation 

obligations entirely on the affected 

EGUs (in which case, the standard will 

reflect a relatively larger part of the 

emission performance level). 

These proposed interpretations of the 

provisions of CAA sections 111(d)(1) 

and (a)(1) are fully consistent with the 

EPA’s overall approach in this 

rulemaking to determining and applying 

the BSER and identifying the 

appropriate level of emission 

performance for the affected EGUs. As 

noted, this approach entails applying 

the BSER on a state-wide basis and, 

based on the BSER, identifying the 

emission performance level for each 

state’s affected EGUs that each state 

must achieve, so that each state may 

then assign the emission limitation 

obligations among its sources. As noted, 

this approach is fully consistent with 

the interconnected nature of the 

electricity system and with the 

principles of federalism that underlie 

CAA section 111(d). 

It should be emphasized that each 

state has many options for assigning the 

emission limitation obligations among 

its affected sources. For example, the 

state could impose emission standards 

that are consistent with the BSER. 

Under these circumstances, the state 

may assign to different affected sources 

emission standards with different levels 

of stringency because the state will have 

determined that those standards are 

consistent with the nature of each 

source’s participation in the state’s 

electricity system. In addition, the state 

could authorize emission trading as part 

of the emission standards for affected 

sources. Under these circumstances, if 

an affected source’s emission level was 

higher than the standard the state 

established for it, the source could 

achieve the standard by purchasing 

additional emission rights through the 

trading program. 

Finally, it should be noted that states 

retain authority under CAA section 116 

and 40 CFR 60.24(g) to impose 

standards of performance that, 

cumulatively, are more stringent than 

the emission performance level.248

10. Combined Categories 

As discussed above, the EPA is 

soliciting comment on combining the 

category of steam EGUs and the category 

of combustion turbines (which include 

NGCC units) into a single category for 

fossil fuel-fired EGUs, for purposes of 

promulgating emission guidelines for 

CO2 emissions. The EPA solicits 

comment on whether combining the 

categories is, as a legal matter, a 

prerequisite for (i) identifying as a 

component of the BSER re-dispatch 

between sources in the two categories 

(i.e., re-dispatch between steam EGUs 

and NGCC units), or (ii) facilitating 

averaging or trading systems that 

include sources in both categories, 

which states may wish to adopt. 

11. Severability 

We consider our proposed findings of 

the BSER with respect to the various 

building blocks to be severable, such 

that in the event a court were to 

invalidate our finding with respect to 

any particular building block, we would 

find that the BSER consists of the 

remaining building blocks. The state 

goals that would result from any 

combination of the building blocks can 

be computed from data included in the 

Goal Computation TSD and its 

appendices using the methodology 

described in the preamble and that TSD. 

12. Solicitation of Comment 

We invite comment on all aspects of 

our proposed interpretation and 

alternate interpretation of the BSER for 

CO2 emissions from existing fossil fuelfired EGUs, both as identified above and 

as further discussed in the Legal 

Memorandum in the docket.249 In 

particular, we invite comment on our 

analysis of the four building blocks as 

components of the BSER, whether any 

other potential measures should be 

considered, our analysis of the 

combinations of building blocks 1 and 

2 and of all four building blocks, and 

the legal, technical, and economic bases 

of our conclusions. With regard to 

comments received during the 

stakeholder meetings, some commenters 

noted that trading programs like RGGI 

have been successful at reducing GHGs, 

and other commenters provided specific 

BSER proposals based on trading and/or 

emissions averaging approaches. We 

specifically request comment on 

whether any of these approaches should 

be considered as the BSER. We also 

specifically invite comment on the 

question, raised by some stakeholders, 

as to whether if measures may be relied 

on in the state plan to achieve emissions 

reductions, they cannot be excluded 

from the scope of the BSER solely 

because they involve actions by entities 

or at locations other than affected 

sources. 

VII. State Goals 

A. Overview 

In this section, the EPA sets out 

proposed state-specific CO2 emission 

performance goals to guide states in 

development of their state plans. The 

proposed goals reflect the EPA’s 

quantification of each state’s average 

emission rate from affected EGUs that 

could be achieved by 2030 and 

sustained thereafter, with interim goals 

that would apply over a 2020–2029 

phase-in period, through reasonable 

implementation, considering the unique 

circumstances of each individual state, 

of the best system of emission reduction 

adequately demonstrated (based on all 

four building blocks) described above. 

In addition, we are taking comment on 

a second set of state-specific goals that 

would reflect less stringent application 

of the same BSER, in this case by 2025, 

with interim goals that would apply 

over a 2020–2024 phase-in period. As 

promulgated in the final rule following 

consideration of comments received, the 

interim and final goals will be binding 

emission guidelines for state plans. 

The proposed goals are expressed in 

the form of state-specific, adjusted 250

output-weighted-average CO2 emission 

rates for affected EGUs. However, states 

are authorized to translate the form of 

the goal to a mass-based form, as long 

as the translated goal achieves the same 

degree of emission limitation.251

The EPA is also proposing that 

measures taken by a state or its sources 


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252The South Point facility is an NGCC power 

plant, and the Navajo, Four Corners, and Bonanza 

facilities are coal-fired power plants. 

253As noted in Section VI.C.5.d above, we are 

requesting comment on whether heat rate 

improvements for non-coal fossil fuel-fired EGUs 

should be part of the basis supporting the BSER, 

with particular reference to the situation of 

geographically isolated jurisdictions such as the 

U.S. territories. 

after the date of this proposal, or 

programs already in place, and which 

result in CO2 emission reductions at 

affected EGUs during the 2020–2030 

period, would apply toward 

achievement of the state’s CO2 goal. 

Thus, states with currently existing 

programs and policies, and states that 

put in place new programs and policies 

early, will be better positioned to 

achieve the goals. 

The EPA is proposing to finalize the 

goal for each state as proposed, and 

adjusted as may be appropriate based on 

comments. A state may demonstrate 

during the comment period that 

application of one of the building blocks 

to that state would not be expected to 

produce the level of emission reduction 

quantified by the EPA because 

implementation of the building block at 

the levels envisioned by the EPA was 

technically infeasible, or because the 

costs of doing so were significantly 

higher than projected by the EPA. While 

the EPA would consider this in setting 

final state goals, the EPA would also 

consider (and would expect commenters 

to address) whether a similar overall 

state goal could still be achieved 

through more aggressive 

implementation of one or more of the 

measures encompassed in the other 

building blocks or through other, 

comparable measures. For example, if a 

state demonstrates during the public 

comment period that the state’s coalfired steam EGUs could only achieve an 

average four percent heat rate 

improvement, instead of the six percent 

that the EPA is proposing to determine 

is achievable from application of 

building block 1, the EPA would not 

adjust the state’s goal to reflect that 

change unless the state also 

demonstrates that it could not get 

additional reductions from application 

of building blocks 2, 3 or 4, or in 

related, comparable measures. 

Each of the building blocks 

establishes a reasonable level of 

reductions, but not necessarily the 

maximum amount that could be 

achieved if that building block, and no 

other, were the basis supporting the 

BSER. Together the building blocks 

establish a reasonable overall level of 

reductions and effort that the EPA 

considers appropriate at this time. This 

amount of emission reductions is 

significant and will require effort and 

adjustments throughout the electricity 

sector. In light of the overall effort to 

achieve the state goals based on a 

combination of all four building blocks 

at the levels specified, the EPA is not 

proposing a higher level of reductions at 

this time, even though the measures in 

the building blocks could be 

implemented more stringently to 

achieve greater emission reductions. 

Because the building blocks each 

establish a reasonable level of emission 

reduction rather than the maximum 

possible level of reduction, the EPA 

expects that, for any particular state, 

even if the application of the measures 

in one building block to that state would 

not produce the level of emission 

reductions reflected in the EPA’s 

quantification for that state, the state 

will be able to reasonably implement 

measures in other of the building blocks 

more stringently, so that the state would 

still be able to achieve the proposed 

goal. Accordingly, the EPA proposes 

that even if a state demonstrates during 

the comment period that application of 

a building block to that state would not 

result in the level of emission 

reductions reflected in the EPA’s 

quantification for that state, then the 

state should also explain why the 

application of the other building blocks 

would not result in greater emission 

reductions than are reflected in the 

EPA’s quantification for that state. In 

light of the fact that the building blocks 

are based on a reasonable level of 

stringency and not the most stringent 

possible level, the EPA expects that 

such offsetting emission reductions at 

the state’s affected EGUs from the 

application of other building blocks will 

be available, so that the EPA will be able 

to finalize the state goals as proposed. 

For example, a state’s inability to meet 

the level of emission reductions 

anticipated through use of one building 

block may free up resources that the 

state could then devote to more 

stringent implementation of another 

building block. This approach would 

mean that overall, the same nationwide 

level of emission reductions as 

proposed would be achieved. The EPA 

invites comment on this aspect of the 

proposal. 

At this time, the EPA is not proposing 

CO2 emission performance goals for 

either Indian country or U.S. territories. 

The EPA does plan to establish CO2

emission goals for both Indian country 

and territories in the future. The EPA 

plans to conduct additional outreach 

before setting these goals. 

Issues related to the establishment of 

CO2 goals and CAA section 111(d) plans 

for Indian country are discussed in 

Section V.D of this preamble. As noted 

in that discussion, the EPA is aware of 

four potentially affected power plants 

located in Indian country: The South 

Point Energy Center, on Fort Mojave 

tribal lands within Arizona; the Navajo 

Generating Station, on Navajo tribal 

lands within Arizona; the Four Corners 

Power Plant, on Navajo tribal lands 

within New Mexico; and the Bonanza 

Power Plant, on Ute tribal lands within 

Utah.252 Data for these four power 

plants have been excluded from the data 

used to compute the proposed state 

goals for Arizona, New Mexico, and 

Utah discussed below. 

With respect to territories, the EPA is 

currently aware of potentially affected 

EGUs in Puerto Rico, the U.S. Virgin 

Islands, and Guam. The EPA requests 

comment on how the BSER would apply 

to these territories, as well as to 

American Samoa or the Northern 

Mariana Islands if potentially affected 

EGUs are subsequently identified in 

those territories. In particular, the EPA 

solicits comment on appropriate 

alternatives for territories that do not 

have access to natural gas.253 Because 

the data sources we have used for 

purposes of establishing renewable 

energy and demand-side energy 

efficiency targets for states do not cover 

all the territories, we also solicit 

comment on ways to determine 

appropriate renewable energy and 

demand-side energy efficiency targets 

using other data sources. 

The remainder of this section 

addresses five sets of topics. First, we 

discuss several issues related to the 

form of the goals. Second, we describe 

the proposed state goals and the 

computation procedure. Third, we 

discuss several types of state flexibility 

with respect to the goals. Fourth, we 

describe the alternate set of goals offered 

for comment and certain other 

approaches we considered. Finally, we 

discuss the proposal’s compatibility 

with the need to ensure a reliable, 

affordable supply of electricity. 

Some of the topics addressed in this 

section are addressed in greater detail in 

supplemental documents available in 

the docket for this rulemaking, 

including the Goal Computation TSD 

and the Greenhouse Gas Abatement 

Measures TSD. Specific topics 

addressed in the various TSDs are noted 

throughout the discussion below. 

B. Form of Goals 

The proposed goals are presented in 

the form of adjusted output-weightedaverage CO2 emission rates that the 

affected fossil fuel-fired EGUs located in 

each state could achieve, on average, 

through application of the measures 


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254We also recognize that even under a massbased approach, adjustments may be appropriate in 

some circumstances to address interstate effects, 

such as when measures undertaken pursuant to one 

state’s plan are expected to be associated with 

decreases in fossil fuel-fired generation and CO2

emissions in another state. These issues are 

discussed below in Section VIII on state plans. 

255As discussed below in Section VIII on state 

plans, we are similarly proposing that states 

choosing a rate-based form of emission performance 

level for their plans should establish a requirement 

for affected EGUs to report hourly net energy 

output. 

256For some EGUs, total net or gross energy 

output also includes useful thermal output, in 

addition to either net or gross electric energy 

output. 

257Some EGUs report gross steam output instead 

of gross electrical load. 

comprising the BSER (or alternative 

control methods). Several aspects of this 

proposed form of goal are worth noting 

at the outset: The use of an emission 

rate-based form (e.g., the quantity of CO2

per MWh of electricity generated), with 

the opportunity for the state to adopt a 

mass-based form (e.g., a cap on the 

tonnage of CO2 emissions); the use of 

output-weighted-average emission rates 

for all affected EGUs in a state rather 

than nationally uniform emission rates 

for all affected EGUs of particular types; 

the use of adjustments to accommodate 

measures that reduce CO2 emissions by 

reducing the quantity of fossil fuel-fired 

generation rather than by reducing the 

CO2 emission rate per MWh generated 

by affected sources; the use of emission 

rates expressed in terms of net rather 

than gross energy output; and the 

adjustability of the goals based on the 

severability of the underlying building 

blocks. 

First, the EPA proposes to use an 

emission rate-based form for the statespecific goals included in the 

guidelines, and to give each state the 

opportunity to translate its rate-based 

goal to an equivalent mass-based form 

for state plan purposes. Each of the two 

forms of goals presents advantages, and 

states have expressed support for having 

the flexibility to use either form. 

Defining emission performance levels in 

a rate-based form provides flexibility to 

accommodate changes in the overall 

quantities of electricity generated in 

response to increases in electricity 

demand. Defining emission performance 

levels in a mass-based form provides 

relative certainty as to the absolute 

emission levels that would be achieved 

as well as relative simplicity in 

accommodating and accounting for the 

emission impacts of a wide variety of 

emission reduction strategies. In light of 

these respective advantages, we propose 

to set an emission rate-based form of 

goal, and to allow any state to translate 

the rate-based goal to an equivalent 

mass-based emission performance level 

for state plan purposes. This approach 

allows each state to maximize the 

advantages it considers optimal and is 

consistent with the state flexibility 

principle that is central to the EPA’s 

development of this program. 

The second aspect noted above 

concerns the proposed choice of statespecific output-weighted-average 

emission rates for all affected EGUs in 

each state rather than nationally 

uniform emission rates for particular 

types of affected EGUs. Here, the EPA’s 

main consideration has been to ensure 

that the proposed goals reflect 

opportunities to manage CO2 emissions 

by shifting generation among different 

types of affected EGUs. Specifically, 

because CO2 emission rates differ 

widely across the fleet of affected EGUs, 

and because transmission 

interconnections typically provide 

system operators with choices as to 

which EGU should be called upon to 

produce the next MWh of generation 

needed to meet demand, opportunities 

exist to manage utilization of high 

carbon-intensity EGUs based on the 

availability of less carbon-intensive 

generating capacity. For states and 

generators, this means that CO2

emission reductions can be achieved by 

shifting generation from EGUs with 

higher CO2 emission rates, such as coalfired EGUs, to EGUs with lower CO2

emission rates, such as NGCC units. Our 

analysis indicates that shifting 

generation among EGUs offers 

opportunities to achieve large amounts 

of CO2 emission reductions at 

reasonable costs. These opportunities 

can be reflected in a goal established in 

the form of an output-weighted-average 

emission rate for multiple affected EGU 

types. Our approach is also consistent 

with the fact that the proportions of 

different EGU types and hence the 

magnitudes of the generation-shifting 

opportunities vary across states, and 

that CAA section 111(d) calls for 

standards of performance to be 

established in state plans rather than on 

a nationwide basis. 

The third aspect noted above 

regarding the proposed form of the goals 

concerns the adjustments made to the 

output-weighted-average emission rates 

in order to accommodate reduced 

utilization of affected EGUs associated 

with measures such as increases in lowand zero-carbon generating capacity and 

demand-side energy efficiency. We 

recognize that these measures support 

reduced overall CO2 mass emissions 

from affected EGUs through reductions 

in the quantity of generation from 

affected EGUs, and not necessarily 

through reductions in the weightedaverage CO2 emission rates of affected 

EGUs. Accordingly, we have 

constructed the emission rate goals in a 

manner that is intended to account for 

these generation quantity-reducing 

measures by making adjustments to the 

values used in the emission rate 

computations. The specific adjustments 

are summarized below in the context of 

the goal computation methodology and 

are described in greater detail in the 

Goal Computation TSD. As described 

below in Section VIII on state plans, we 

are proposing that a state choosing a 

rate-based form of goal would be able to 

make analogous adjustments when 

assessing monitored emission 

performance so that measures that 

support avoided generation at affected 

EGUs could be used to help the state 

meet the rate-based emission 

performance level reflected in its plan. 

We note that adjustments of this nature 

are not necessary when a plan’s 

emission performance level is based on 

the mass of CO2 emissions 254 rather 

than on CO2 emission rates, because the 

emission-reducing effects of reduced 

generation at affected EGUs are evident 

in the EGUs’ reported CO2 mass 

emissions. 

The fourth aspect noted above 

concerns the proposed expression of the 

goals in terms of net energy output 255— 

that is, energy output encompassing net 

MWh of generation measured at the 

point of delivery to the transmission 

grid rather than gross MWh of 

generation measured at the EGU’s 

generator.256 The difference between net 

and gross generation is the electricity 

used at a plant to operate auxiliary 

equipment such as fans, pumps, motors, 

and pollution control devices. Because 

improvements in the efficiency of these 

devices represent opportunities to 

reduce carbon intensity at existing 

affected EGUs that would not be 

captured in measurements of emissions 

per gross MWh, we are proposing goals 

expressed in terms of net generation. 

Nearly all EGUs already have in place 

the equipment necessary to determine 

and report hourly net generation, and 

we believe that the proposed reporting 

requirement would therefore not be 

burdensome. However, we also 

recognize that at present EGUs report 

gross rather than net load 257 to us under 

40 CFR Part 75, and that the proposed 

GHG standards of performance for new 

EGUs are expressed in terms of gross 

generation (although we sought 

comment on the use of net generation 

instead). We therefore specifically seek 

comment on whether the goals and 

reporting requirements for existing 

EGUs should be expressed in terms of 


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258The EPA has not developed goals for Vermont 

and the District of Columbia because current 

information indicates those jurisdictions have no 

affected EGUs. Also, as noted above, the EPA is not 

proposing goals for Indian country or U.S. 

territories at this time. 

259 In the case of new capacity that is not zerocarbon, an adjustment would also be required to the 

emissions value used in computing the weightedaverage emission rate. This procedure is discussed 

further in the Goal Computation TSD. 

260EGUs whose capacity, fossil fuel combustion, 

or electricity sales were insufficient to qualify them 

as affected EGUs were not included in the goal 

computations. Most simple cycle combustion 

Continued 

gross generation instead of net 

generation for consistency with existing 

reporting requirements and with the 

proposed requirements under the GHG 

standards of performance for new EGUs. 

The final aspect noted above has to do 

with the severability of the four building 

blocks, discussed in Section VI above, 

upon which the goals are based. 

Because the building blocks can be 

implemented independently of one 

another and the goals are the sum of the 

emission reductions from all of the 

building blocks, if any of the building 

blocks is found to be an invalid basis for 

the ‘‘best system of emission reduction 

. . . adequately demonstrated,’’ the 

goals would be adjusted to reflect the 

emissions reductions from the 

remaining building blocks. As noted 

above, the state goals that would result 

from any combination of the building 

blocks can be computed from data 

included in the Goal Computation TSD 

and its appendices using the 

methodology described below and in 

that TSD. 

We invite comment on all aspects of 

the proposed form of the goals. 

C. Proposed Goals and Computation 

Procedure 

The EPA has developed proposed 

goals for state plans reflecting 

application of the BSER, based on all 

four building blocks described earlier, to 

pertinent data for each state. The goals 

are intended to represent CO2 emission 

rates achievable by 2030 after a 2020– 

2029 phase-in period on an outputweighted-average basis collectively by 

all of a state’s affected EGUs, with 

certain computation adjustments 

described below to reflect the potential 

to achieve mass emission reductions by 

avoiding fossil fuel-fired generation. For 

each state, in addition to the final goal, 

the EPA has developed an interim goal 

that would apply during the 2020–2029 

period on a cumulative or average basis 

as the state progresses toward the final 

goal. The proposed goals are set forth in 

Table 8 below, followed by a 

description of the computation 

methodology. (The issue of how states 

could demonstrate emission 

performance consistent with the interim 

and final goals is addressed in Section 

VIII on state plans.) 

TABLE 8—PROPOSED STATE 258

GOALS

[Adjusted output-weighted-average pounds of 

CO2 per net MWh from all affected fossil 

fuel-fired EGUs] 

State Interim 

goal 

Final 

goal 

Alabama ........................ 1,147 1,059 

Alaska ........................... 1,097 1,003 

Arizona * ........................ 735 702 

Arkansas ....................... 968 910 

California ....................... 556 537 

Colorado ....................... 1,159 1,108 

Connecticut ................... 597 540 

Delaware ....................... 913 841 

Florida ........................... 794 740 

Georgia ......................... 891 834 

Hawaii ........................... 1,378 1,306 

Idaho ............................. 244 228 

Illinois ............................ 1,366 1,271 

Indiana .......................... 1,607 1,531 

Iowa .............................. 1,341 1,301 

Kansas .......................... 1,578 1,499 

Kentucky ....................... 1,844 1,763 

Louisiana ...................... 948 883 

Maine ............................ 393 378 

Maryland ....................... 1,347 1,187 

Massachusetts .............. 655 576 

Michigan ....................... 1,227 1,161 

Minnesota ..................... 911 873 

Mississippi .................... 732 692 

Missouri ........................ 1,621 1,544 

Montana ........................ 1,882 1,771 

Nebraska ...................... 1,596 1,479 

Nevada ......................... 697 647 

New Hampshire ............ 546 486 

New Jersey ................... 647 531 

New Mexico * ................ 1,107 1,048 

New York ...................... 635 549 

North Carolina .............. 1,077 992 

North Dakota ................ 1,817 1,783 

Ohio .............................. 1,452 1,338 

Oklahoma ..................... 931 895 

Oregon .......................... 407 372 

Pennsylvania ................ 1,179 1,052 

Rhode Island ................ 822 782 

South Carolina .............. 840 772 

South Dakota ................ 800 741 

Tennessee .................... 1,254 1,163 

Texas ............................ 853 791 

Utah * ............................ 1,378 1,322 

Virginia .......................... 884 810 

Washington ................... 264 215 

West Virginia ................ 1,748 1,620 

Wisconsin ..................... 1,281 1,203 

Wyoming ....................... 1,808 1,714 

* Excludes EGUs located in Indian country 

within the state. 

The proposed goals are expressed as 

adjusted output-weighted-average 

emission rates for all affected EGUs in 

a state. As discussed earlier in this 

section, a goal expressed as an 

unadjusted output-weighted-average 

emission rate would fail to account for 

mass emission reductions from 

reductions in the total quantity of fossil 

fuel-fired generation associated with 

state plan measures that increase low- or 

zero-carbon generating capacity or 

demand-side energy efficiency. 

Accordingly, under the proposed goals, 

the emission rate computation includes 

an adjustment designed to reflect those 

mass emission reductions. The 

adjustment is made by estimating the 

annual net generation associated with 

an achievable amount of qualifying new 

low-carbon and zero-carbon generating 

capacity, as well as the annual avoided 

generation associated with an 

achievable portfolio of demand-side 

energy efficiency measures, and adding 

those MWh amounts to the energy 

output from affected units that would 

have been used in an unadjusted 

output-weighted-average emission rate 

computation.259 Mathematically, this 

adjustment has the effect of spreading 

the measured CO2 emissions from the 

state’s affected EGUs over a larger 

quantity of energy output, thus resulting 

in an adjusted emission rate lower than 

the unadjusted emission rate. (As 

discussed below in Section VIII on state 

plans, we are proposing that a state 

could make analogous adjustments to 

compliance measurement approaches 

under its state plan, thereby enabling 

the state to adopt an emission rate-based 

form of emission performance level 

while still being able to rely on low- or 

zero-carbon capacity deployment 

programs and demand-side energy 

efficiency as components of its plan.) 

The methodology used to compute 

each state’s proposed goal is 

summarized on a step-by-step basis 

below. The methodology is described in 

more detail in the Goal Computation 

TSD, which includes a numerical 

example illustrating the full procedure. 

The development of the data inputs 

used in the computation procedure is 

discussed in Section VI above and in the 

Greenhouse Gas Abatement Measures 

TSD. 

Step 1 (compilation of baseline data). 

On a state-by-state basis, we obtained 

total annual quantities of CO2

emissions, net generation (MWh), and 

capacity (MW) from reported 2012 data 

for all affected EGUs.260 For each state, 


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turbines were excluded on this basis. See the 

applicability criteria described in Section V.B. 

above. 

261The emission and generation totals for the 

‘‘other’’ group also reflect the portion of affected 

cogeneration units’ total CO2 emissions and total 

energy output corresponding to those units’ useful 

thermal output. 

262Assuming it meets other applicability criteria, 

an EGU would be affected if it had commenced 

construction by January 8, 2014 (the data of Federal 

Register publication of the proposed GHG NSPS for 

new EGUs). 

263For example, if the data developed in Step 1 

showed equal quantities of MWh generated by the 

coal-fired steam EGU group and the oil/gas-fired 

steam EGU group, then any overall reduction in the 

MWh generated by these two groups due to a 

commensurate increase in the MWh generated by 

the less carbon-intensive NGCC group would be 

split equally between the coal-fired steam group 

and the oil/gas-fired steam group. 

264We did not estimate any change in utilization, 

generation, or emissions for the state’s ‘‘other’’ 

group of IGCC units and simple-cycle combustion 

turbines in Step 3. 

265Expressed as a formula, the equation for the 

annual rate computation is: 

[(Coal gen. × Coal emission rate) + (OG gen. × OG 

emission rate) + (NGCC gen. × NGCC emission rate) 

+ ‘‘Other’’ emissions]/[Coal gen. + OG gen. + NGCC 

gen. + ‘‘Other’’ gen. + Nuclear gen. + RE gen. + EE 

gen.] 

This formula and its elements are further 

explained in the Goal Computation TSD, as well as 

in the text above. 

we aggregated the 2012 data for all coalfired steam EGUs as one group, all oiland gas-fired steam EGUs as a second 

group, and all NGCC units as a third 

group. We aggregated the 2012 data for 

all remaining affected EGUs (i.e., 

integrated gasification combined-cycle 

(IGCC) units and any simple-cycle 

combustion turbines satisfying relevant 

thresholds for qualification as affected 

EGUs) as a fourth, ‘‘other’’ group.261 To 

these totals for affected EGUs operating 

in 2012, we added estimates for other 

EGUs not yet in operation in 2012 that 

are affected EGUs for purposes of this 

emission guideline.262 Capacity and 

emission rate data inputs for the post2012 affected EGUs were obtained from 

the NEEDS database maintained by the 

EPA for use with the Integrated 

Planning Model (IPM). Generation data 

inputs for the post-2012 affected EGUs 

were estimated based on the average 

2012 utilization rates for recently 

constructed EGUs of the same types; for 

example, we estimated in this step that 

the post-2012 NGCC units would 

operate at a 55 percent utilization rate 

on average. 

Step 2 (application of building block 

1). The total CO2 emissions amount for 

the coal-fired steam EGU group in each 

state from Step 1 was reduced by six 

percent, reflecting our assessment of the 

average opportunity to reduce CO2

emission rates across the existing fleet 

of coal-fired steam EGUs through heat 

rate improvements that is technically 

achievable at a reasonable cost. 

Step 3 (application of building block 

2). If the generation data for the NGCC 

group in a state developed in Step 1 

showed average annual utilization 

below 70 percent of those units’ 

maximum possible output, and the 

generation data developed in Step 1 also 

included generation from the coal-fired 

steam or oil/gas-fired steam EGU groups 

in that state, the generation and 

emissions figures for the NGCC group 

were increased, and the generation and 

emissions figures for the coal-fired and 

oil/gas-fired steam EGU groups from 

Step 2 were proportionately 263

decreased, to reflect an estimated 

potential increase in utilization of the 

NGCC group to a maximum of 70 

percent. In this step, the total (across all 

four groups) of the state’s fossil fuelfired generation was maintained at the 

amount computed in Step 1, but to the 

extent that in the analysis a portion of 

the total fossil generation was shifted 

from the coal-fired and oil/gas-fired 

steam EGU groups, which have higher 

CO2 emission rates, to the NGCC group, 

which has a lower CO2 emission rate, 

the total (across all four groups) of the 

state’s CO2 emissions was reduced.264

Step 4 (application of building block 

3). We estimated the total quantities of 

generation from renewable generating 

capacity and from under-construction or 

preserved nuclear capacity for each state 

using the approaches described in 

Section VI.C.3 above. Separate estimates 

of renewable generation were computed 

for each year of the plan period for each 

state based on the state’s 2012 

renewable generation and a regional 

growth factor. Nuclear generation was 

estimated as the amount of underconstruction and preserved nuclear 

capacity for each state operated at a 

utilization rate of 90 percent, consistent 

with recent industry-wide average 

utilization rates for nuclear units. 

Step 5 (application of building block 

4). We estimated the total MWh amount 

by which generation from each state’s 

affected EGUs would be cumulatively 

reduced in each year of the plan period 

associated with implementation in that 

state of demand-side energy efficiency 

programs resulting in annual 

incremental reductions in the state’s 

electricity usage (relative to usage 

absent those programs) of 1.5 percent 

each year, as described in Section VI.C.4 

above. Separate estimates were 

developed for each year to reflect the 

fact that energy efficiency programs that 

are implemented on an ongoing basis 

would be expected to produce larger 

cumulative impacts on total annual 

electricity usage over time. For states 

that are net importers of electricity, the 

estimated reduction in the generation by 

the state’s affected EGUs was scaled 

down to reflect an expectation that a 

portion of the generation avoided by the 

demand-side energy efficiency would 

occur at EGUs in other states. 

Step 6 (computation of annual rates). 

We computed adjusted outputweighted-average CO2 emission rates for 

each state by dividing (1) the total CO2

emissions for the coal-fired steam EGU, 

oil- and gas-fired steam EGU, NGCC 

unit, and ‘‘other’’ affected fossil EGU 

groups from Step 3 above by (2) the total 

of (a) the total net energy output 

(expressed in MWh) for the four groups 

from Step 1 above plus (b) the estimated 

annual net generation from renewable 

and nuclear generating capacity from 

Step 4 above plus (c) the estimated 

cumulative annual MWh amount saved 

through demand-side energy efficiency 

from Step 5 above.265 We performed 

these computations separately for each 

year from 2020 to 2029, using the 

respective cumulative annual MWh 

savings figures developed in Steps 4 and 

5. 

Step 7 (computation of interim and 

final goals). The final 2030 goal for each 

state is the annual rate computed for 

2029 for the state from Step 6 above. We 

computed the 2020–2029 interim goal 

for each state as the simple average of 

the annual rates computed for each of 

the years from 2020 to 2029 for the state 

from Step 6 above. 

It bears emphasis that the procedure 

described above is proposed to be used 

only to determine state goals, and the 

particular data inputs used in the 

procedure are not intended to represent 

specific requirements that would apply 

to any individual EGU or to the 

collection of EGUs in any state. The 

specific requirements applicable to 

individual EGUs, to the EGUs in a given 

state collectively, or to other affected 

entities in the state, would be based on 

the standards of performance 

established through that state’s plan. 

The details of how states could attain 

emission performance levels consistent 

with the goals through different state 

plan approaches that recognize emission 

reductions achieved through all the 

building blocks are discussed further in 

Section VIII on state plans. 

We invite comment on all aspects of 

the goal computation procedure. (Note 

that we also invite comment on certain 

specific alternate data inputs to the 

procedure in Section VI.C above.) We 

also specifically invite comment on the 

state-specific historical data to which 


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266 40 CFR 60.22(b)(5). We do not propose to reopen that portion of the implementing regulations 

in this rulemaking. 

267 Id. 

the building blocks are applied in order 

to compute the state goals, as well as the 

state-specific data used to develop the 

state-specific data inputs for building 

blocks 3 and 4. These data are contained 

in the Goal Computation TSD and the 

Greenhouse Gas Abatement Measures 

TSD. 

With respect to building block 2, we 

specifically request comment on the 

following alternate procedure: In Step 3, 

to the extent that generation from a 

state’s NGCC group was increased 

consistent with the NGCC utilization 

rate target, in order to maximize the 

resulting emission reductions, we 

would decrease generation from the 

state’s coal-fired steam group first, and 

then decrease generation from the state’s 

oil/gas-fired steam group (instead of 

decreasing generation from the coalfired steam and oil/gas-fired steam 

groups proportionately). 

With respect to building block 4, we 

specifically invite comment on the 

alternative in Step 5 of scaling up the 

estimated reduction in the generation by 

affected EGUs in net electricityexporting states to reflect an expectation 

that a portion of the generation avoided 

in conjunction with the demand-side 

energy efficiency efforts of other, net 

electricity-importing states would occur 

at those EGUs, analogous to the 

proposed adjustment for net electricityimporting states described in Step 5. We 

also request comment on the alternative 

of making no adjustment in Step 5 for 

either net electricity-importing or net 

electricity-exporting states. These 

alternatives are discussed in the Goal 

Computation TSD. 

We also request comment on whether 

CO2 emission reductions associated 

with other measures not currently 

included in any of the four proposed 

building blocks should be included in 

the state goals. 

D. State Flexibilities 

As promulgated in the final rule 

following consideration of comment, the 

state-specific goals will be binding 

emission guidelines. States’ ability to 

achieve emission performance levels 

consistent with the binding goals is 

enhanced by several distinct types of 

flexibility: (i) Choices as to the measures 

employed, including the timing of their 

implementation; (ii) the ability to 

translate from a rate-based form of goal 

to a mass-based form of goal; and (iii) 

the opportunity to pursue multi-state 

plan approaches. 

First, a core flexibility provided under 

CAA section 111(d) is that while states 

are required to establish standards of 

performance that reflect the degree of 

emission limitation from application of 

the control measures that the EPA 

identifies as the BSER, they need not 

mandate the particular control measures 

the EPA identifies as the basis for its 

BSER determination. In developing the 

building block data inputs applied to 

each state’s historical data to develop 

the goals, the EPA targeted reasonably 

achievable rather than maximum 

performance levels. The overall goals 

therefore represent reasonably 

achievable emission performance levels 

that provide states with flexibility to 

pursue some building blocks more 

extensively and others less extensively 

than the degree reflected in the EPA’s 

data inputs while meeting the overall 

goals. States can also choose to include 

in their plans other measures that 

reduce CO2 emissions at affected EGUs 

but that are not included in the building 

blocks. 

Further, by allowing states to 

demonstrate emission performance by 

affected EGUs on an average basis over 

a multi-year interim plan period of as 

long as ten years, the EPA’s proposed 

approach increases states’ flexibility to 

choose among alternative potential plan 

measures. For example, by taking 

advantage of the multi-year flexibility, a 

state could choose to rely more heavily 

in its plan on measures whose 

effectiveness tends to grow over time, 

such as demand-side energy efficiency 

programs. This flexibility could also 

help states address concerns about 

stranded assets, for example, by 

enabling states to defer imposition of 

requirements on EGUs that may be 

scheduled to retire after 2020 but before 

2029. 

The second type of flexibility noted 

above is that while the EPA is proposing 

to establish goals in an emission ratebased form, we are also proposing to 

provide states with the flexibility to 

translate the rate-based goals to massbased goals in order to accommodate 

states’ potential interest in having 

emission performance requirements 

measured in absolute tons. For example, 

the northeastern and Mid-Atlantic states 

that currently participate in the massbased Regional Greenhouse Gas 

Initiative (RGGI) may choose to develop 

state plans (or a multi-state plan, as 

noted below) establishing mass-based 

emission performance levels designed to 

be met at least in part through standards 

of performance based on RGGI’s existing 

market-based CO2 emission budget 

trading program. Because the use of 

mass-based plans can simplify the 

process of accounting for the CO2

reduction impacts of a variety of 

measures, the EPA believes the 

flexibility to adopt mass-based emission 

performance levels can facilitate plan 

development and could be attractive to 

states that do not already participate in 

mass-based emission reduction 

programs as well. 

Third, the EPA’s approach allows 

states to submit multi-state plans. The 

EPA expects this flexibility to reduce 

the cost of achieving the state goals and 

therefore expects it to be attractive to 

states. For example, the RGGIparticipating states could choose to 

submit a multi-state mass-based plan 

that demonstrates emission performance 

by affected EGUs on a multi-state basis. 

Additional states may also choose to 

join a multi-state plan. The mechanics 

of translating rate-based goals into massbased goals and considerations related 

to multi-state plans are discussed below 

in Section VIII on state plans. 

Some stakeholders have suggested 

that states themselves should be 

allowed to quantify the level of 

emission reduction resulting from the 

application of BSER or, if the EPA 

establishes goals, the states should be 

allowed to adjust the goals or to treat the 

goals established by the EPA as advisory 

rather than binding. Consistent with the 

existing implementing regulations for 

CAA section 111(d) at 40 CFR part 60, 

this quantification is the EPA’s role.266

As discussed in the Legal 

Memorandum, CAA section 111(d) 

directs the EPA to ‘‘prescribe 

regulations which shall establish a 

procedure similar to that provided by 

[CAA section 110] under which each 

State shall submit’’ a section 111(d) 

state plan. As noted in Section II.D of 

this preamble, the EPA promulgated 

implementing regulations in 1975, and 

has revised parts of them since. The 

regulations set out a multi-step process 

for the development and approval of 

state plans, and assign responsibility for 

the various steps in the process to the 

EPA or the states. The regulations 

provide that the EPA is to promulgate 

an ‘‘emission guideline that reflects the 

application of the best system of 

emission reduction (considering the cost 

of such reduction) that has been 

adequately demonstrated for’’ affected 

sources.267 In this manner, the 

regulations make clear that the EPA 

determines the BSER. In this 

rulemaking, as discussed above, the 

EPA identifies the BSER. In addition, in 

this rulemaking, the EPA applies the 

BSER to each state, and then, for each 

state, calculates the average emission 

rate that, in the words of the regulations 

just quoted, ‘‘reflects the application of 


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268 Id. We do not propose to re-open that portion 

of the implementing regulations in this rulemaking. 

269 In the event that a state becomes concerned 

about its ability to meet the goal that the EPA 

promulgates for it, the state may submit to the EPA 

a petition for reconsideration, if that petition is 

based on relevant information not available during 

the comment period. See CAA section 307(d)(7)(B). 270See footnote accompanying Table 8 above. 

the [BSER].’’ That average emission rate 

is the state goal. 

By the same token, because the state 

goals are an integral part of the emission 

guidelines that the framework 

regulations authorize the EPA to 

establish, the goals are binding, and the 

states, in their CAA section 111(d) 

plans, must meet those goals and may 

not make them less stringent. This 

matter, too, is resolved by the 

implementing regulations.268 To 

reiterate, the proposed state goals 

represent the level of performance that 

is achievable through application of the 

BSER to the pertinent data for each 

individual state. States have the 

opportunity to comment on the 

proposed BSER, the proposed 

methodology for computing state goals 

based on application of the BSER, and 

the state-specific data that is proposed 

for use in the computations. We expect 

that the states will have an adequate 

opportunity to comment on the state 

goals during the comment period. Once 

the final goals have been promulgated, 

and adjusted as may be appropriate 

based on comments to address any 

factual errors in the analysis, the states 

will be able to meet them because they 

will represent the application of BSER 

to the states’ affected sources. In 

addition, states have several types of 

flexibilities in developing their state 

plans: They have flexibility regarding 

the selection of the measures upon 

which they choose to rely and a 10-year 

time period over which to reach full 

implementation of these measures, and 

they can use rate-based or mass-based 

approaches. In addition, as we have 

noted, multi-state coordination offers 

states an opportunity to achieve 

additional emission reductions and 

reduce implementation costs. These 

flexibilities, discussed further in Section 

VIII of this preamble, ensure that states 

will be able to achieve their final CO2

emission performance goals and that no 

special provision for state adjustment of 

goals outside the normal notice-andcomment rulemaking process is 

warranted.269

E. Alternate Goals Offered for Comment 

and Other Approaches Considered 

In addition to the proposed statespecific emission rate-based goals 

described above, the EPA has developed 

for public comment an alternate set of 

goals reflecting less stringent 

application of the building blocks and a 

shorter implementation period. The 

alternate final goals represent emission 

performance that would be achievable 

by 2025, after a 2020–2024 phase-in 

period, with interim goals that would 

apply during the 2020–2024 period on 

a cumulative or average basis as states 

progress toward the final goals. 

Because the time period for 

implementation relates directly to the 

emission reductions that are achievable 

and therefore what measures, and at 

what level of stringency, constitute the 

BSER, the alternate goals reflect several 

differences in data inputs from the 

proposed goals. Specifically, a value of 

four percent (instead of six percent) was 

used for the potential improvement in 

carbon intensity of coal-fired EGUs in 

Step 2; a value of 65 percent (instead of 

70 percent) was used for the potential 

annual utilization rate of NGCC units in 

Step 3; and a value of one percent 

(instead of 1.5 percent) was used for the 

annual incremental electricity savings 

achievable through a portfolio of 

demand-side energy efficiency programs 

in Step 5. (No change was made to the 

data inputs regarding less carbonintensive generating capacity in Step 4.) 

As noted above, the alternate goals also 

reflect a shortening of the proposed 

phase-in period from ten years (2020– 

2029) to five years (2020–2024) to reflect 

an expectation that less stringent goals 

could be achieved in less time. Steps 5, 

6, and 7 of the goal computation 

procedure therefore were performed for 

the span of years from 2020 to 2024 

rather than for the span from 2020 to 

2029. The alternate goals are set forth in 

Table 9 below. 

TABLE 9—ALTERNATE STATE 270

GOALS

[Adjusted output-weighted-average pounds of 

CO2 per net MWh from all affected fossil 

fuel-fired EGUs] 

State Interim 

goal 

Final 

goal 

Alabama ........................ 1,270 1,237 

Alaska ........................... 1,170 1,131 

Arizona * ........................ 779 763 

Arkansas ....................... 1,083 1,058 

California ....................... 582 571 

Colorado ....................... 1,265 1,227 

Connecticut ................... 651 627 

Delaware ....................... 1,007 983 

Florida ........................... 907 884 

Georgia ......................... 997 964 

Hawaii ........................... 1,446 1,417 

Idaho ............................. 261 254 

Illinois ............................ 1,501 1,457 

Indiana .......................... 1,715 1,683 

Iowa .............................. 1,436 1,417 

Kansas .......................... 1,678 1,625 

Kentucky ....................... 1,951 1,918 

TABLE 9—ALTERNATE STATE 270

GOALS—Continued 

[Adjusted output-weighted-average pounds of 

CO2 per net MWh from all affected fossil 

fuel-fired EGUs] 

State Interim 

goal 

Final 

goal 

Louisiana ...................... 1,052 1,025 

Maine ............................ 418 410 

Maryland ....................... 1,518 1,440 

Massachusetts .............. 715 683 

Michigan ....................... 1,349 1,319 

Minnesota ..................... 1,018 999 

Mississippi .................... 765 743 

Missouri ........................ 1,726 1,694 

Montana ........................ 2,007 1,960 

Nebraska ...................... 1,721 1,671 

Nevada ......................... 734 713 

New Hampshire ............ 598 557 

New Jersey ................... 722 676 

New Mexico * ................ 1,214 1,176 

New York ...................... 736 697 

North Carolina .............. 1,199 1,156 

North Dakota ................ 1,882 1,870 

Ohio .............................. 1,588 1,545 

Oklahoma ..................... 1,019 986 

Oregon .......................... 450 420 

Pennsylvania ................ 1,316 1,270 

Rhode Island ................ 855 840 

South Carolina .............. 930 897 

South Dakota ................ 888 861 

Tennessee .................... 1,363 1,326 

Texas ............................ 957 924 

Utah * ............................ 1,478 1,453 

Virginia .......................... 1,016 962 

Washington ................... 312 284 

West Virginia ................ 1,858 1,817 

Wisconsin ..................... 1,417 1,380 

Wyoming ....................... 1,907 1,869 

* Excludes EGUs located in Indian country 

in the state. 

The EPA recognizes that its approach 

to the alternate goals, comprising less 

stringent requirements in each of the 

building blocks to be achieved over a 

shorter compliance horizon, follows the 

logic of including time as one of the 

functions of the BSER determination. At 

the same time, we also recognize that 

the components of the alternate goals 

may reflect an overly conservative 

approach. Specifically, the alternate 

goals as set forth above may 

underestimate the extent to which the 

key elements of the four building 

blocks—achieving heat rate 

improvements at EGUs, switching 

generation to NGCC facilities, fostering 

the penetration of renewable resources 

or improving year-to-year end-use 

energy efficiency—can be achieved 

rapidly while preserving reliability and 

remaining reasonable in cost. 

Accordingly, we request comment on 

the alternate goals, particularly with 

respect to whether any one or all of the 

building blocks in the alternate goals 


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271See the Resource Adequacy and Reliability 

Analysis TSD, available in the docket. 

can be applied at a greater level of 

stringency: Can the heat rate 

improvement value be set at a level 

above four percent, even six percent? 

Can NGCC capacity be dispatched at a 

utilization rate above 65 percent? Can 

annual incremental electricity savings 

be achieved at a rate higher than one 

percent? 

It is worth noting that the EPA 

projects that the alternate goals will 

achieve emission reductions equal to 23 

percent below 2005 level in 2025. The 

EPA’s analysis shows that under the 

proposed goals described in Section 

VII.C above, power sector emissions will 

be 29 percent below 2005 levels in 2025, 

suggesting that the kinds of changes 

contemplated in the four building 

blocks, even as early as 2025, will be 

yielding reductions far greater than the 

23 percent projected for the alternate 

goals as set forth above in this 

subsection. 

The EPA has considered other 

approaches to setting goals. In 

particular, given the interconnected 

nature of the power sector and the 

importance of opportunities for shifting 

generation among EGUs, we considered 

whether goals should be set on a multistate basis reflecting the scope of 

existing regional transmission control 

areas. We also considered whether goals 

should be set on a state-specific basis, 

but regional rather than state-specific 

evaluations should be used to assess the 

estimated opportunities to reduce 

utilization of the most carbon-intensive 

EGUs by shifting generation to less 

carbon-intensive EGUs. A potential 

advantage of using regional evaluations 

is the ability to recognize additional 

emission reduction opportunities that 

would be available at reasonable costs 

based on a more complete 

representation of the capabilities of 

existing infrastructure to accommodate 

shifts in generation among EGUs in 

multiple states. We request comment on 

whether, and if so how, the EPA should 

incorporate greater consideration of 

multi-state approaches into the goalsetting process, and on the issue of 

whether, and if so how, the potential 

cost savings associated with multi-state 

approaches should be considered in 

assessing the reasonableness of the costs 

of state-specific goals. 

F. Reliable Affordable Electricity 

Many stakeholders raised concerns 

that this regulation could affect the 

reliability of the electric power system. 

The EPA agrees that reliability must be 

maintained and in designing this 

proposed rulemaking has paid careful 

attention to this issue. The EPA has met 

on several occasions with staff and 

managers from the Department of 

Energy and the Federal Energy 

Regulatory Commission to discuss our 

approach to the rule and its potential 

impact on the power system. EPA staff 

and managers have also had numerous 

discussions with state public utility 

commissioners and their staffs to get 

their suggestions and advice concerning 

this rule, including how to address 

reliability concerns. 

In addition, the EPA met with 

independent system operators several 

times to discuss any potential impact of 

this rule on grid reliability. The ISO/ 

RTO Council, a national organization of 

electric grid operators, offered analytic 

support to help states design programs 

that do not compromise the regional 

bulk power system. They also offered to 

help states develop regional approaches 

which may reduce costs and strengthen 

the reliability of the electricity grid. 

Specifically, the ISO/RTO Council has 

suggested that ISOs and RTOs could 

provide analytic support to help states 

develop and implement their plans. The 

ISOs and RTOs have the capability to 

model the system-wide effects of 

individual state plans. Providing 

assistance in this way, they felt, would 

allow states with borders that fall within 

an ISO or RTO footprint to assess the 

system-wide impacts of potential state 

plan approaches. In addition, as the 

state implements its plan, ISO/RTO 

analytic support would allow the state 

to monitor the effects of its plan on the 

regional electricity system. ISO/RTO 

analytic capability could help states 

assure that their plans are consistent 

with region-wide system reliability. The 

ISO/RTO Council suggested that the 

EPA ask states to consult with the 

applicable ISO/RTO in developing their 

state plans. The EPA agrees with this 

suggestion and encourages states with 

borders that fall within one or more ISO 

or RTO footprints to consult with the 

relevant ISOs/RTOs. 

The EPA has met with the U.S. 

Department of Agriculture as well to 

discuss how we can address the 

concerns of small, relatively isolated 

power generators in rural America and 

especially the electric cooperatives. 

Many of these entities have special 

challenges, as they may have small, 

older carbon-intensive assets and might 

have particular challenges meeting 

carbon requirements. 

With all of this in mind, the EPA in 

determining the BSER looked 

specifically at the reasonableness of the 

costs of control options in part to ensure 

that the options would not have a 

negative effect on system reliability. The 

BSER, including each of the building 

blocks, was determined to be feasible at 

reasonable costs over the timeframe 

proposed here. Further, under the Clean 

Air Act the states are given the 

flexibility to design state plans that 

include any measure or combination of 

measures to achieve the required 

emission limitations. States are not 

required to use each of the measures 

that the EPA determines constitute the 

BSER or use those measures to the same 

degree or extent that the EPA 

determines is feasible at a reasonable 

cost. Thus, each state has the flexibility 

to choose the most cost-effective 

measures given that state’s energy 

profile and economy, as long as the state 

achieves the reductions necessary to 

meet its goal. Many market-based 

approaches which states may choose 

reduce the costs of compliance. They 

can allow certain units that are seldom 

used to remain in operation if they are 

needed for reliability purposes. Multistate approaches also reduce costs and 

stress on the grid and so can help to 

reduce any concern about electricity 

reliability. 

States may choose measures that 

would ease pressures on system 

reliability. This is true for many 

demand-side management approaches, 

including programs to encourage enduse energy efficiency, distributed 

generation, and combined heat and 

power, which actually reduce demand 

for centrally generated power and thus 

relieve pressure on the grid. 

The EPA is proposing a 10-year 

period over which to achieve the full 

required CO2 reductions, and we would 

expect this to further relieve any 

pressure on grid reliability. This 

relatively long planning and 

implementation period provides states 

with substantial flexibility regarding 

methods and timing of achieving 

emission reductions. 

The EPA’s supporting analysis for this 

rule includes an examination of the 

effects of the rule on regional resource 

adequacy.271 The EPA’s analysis looked 

at the types of changes in the generation 

fleet that were projected to occur 

through retirements, additional 

generation and energy efficiency. The 

analysis did not raise concerns over 

regional resource adequacy. The EPA 

further examined how the policy 

options impacted the flows and 

transfers of electricity that occur to meet 

reserve margins. None of the 

interregional changes in the policy cases 

suggested that there would be increases 

in flows that would raise significant 

concerns about grid congestion or grid 

management. Moreover, the time 


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272See 40 CFR 49.1 to 49.11. 

horizon for compliance with this rule 

will permit environmental and 

reliability planners to coordinate these 

changes and address potential concerns 

before they arise. 

The EPA concludes that the proposed 

rule will not raise significant concerns 

over regional resource adequacy or raise 

the potential for interregional grid 

problems. The EPA believes that any 

remaining local issues can be managed 

through standard reliability planning 

processes. The flexibility inherent in the 

rule is responsive to the CAA’s 

recognition that state plans for emission 

reduction can, and must, be consistent 

with a vibrant and growing economy 

and reliable, affordable electricity to 

support that economy. The EPA 

welcomes comments and suggestions on 

this issue. 

VIII. State Plans 

A. Overview 

After the EPA establishes the statespecific rate-based CO2 goals in the 

emission guidelines, as described in 

Section VII above, each state must then 

develop, adopt, and submit its state plan 

under CAA section 111(d). To do so, the 

state must first determine the emission 

performance level it will include in its 

plan, which entails deciding whether it 

will adopt the rate-based CO2 goal set by 

the EPA or translate the rate-based goal 

to a mass-based goal. 

The state must then establish an 

emission standard or set of emission 

standards, and, perhaps other measures, 

along with implementing and enforcing 

measures, that will achieve a level of 

emission performance that is equal to or 

better than the level specified in the 

state plan. 

The state must then adopt the state 

plan through certain procedures, which 

include a state hearing. Within the time 

period specified in the emission 

guidelines (from as early as June 30, 

2016 to as late as June 30, 2018, 

depending on the state’s circumstances), 

the state must submit its complete state 

plan to the EPA. The EPA then must 

determine whether to approve or 

disapprove the plan. If a state does not 

submit a plan, or if the EPA does not 

approve a state’s plan, then the EPA 

must establish a plan for the state. 

As discussed in Section V.D of this 

preamble, in the case of a tribe that has 

one or more affected EGUs located in its 

area of Indian country, if the EPA 

determines that a CAA section 111(d) 

plan is necessary or appropriate, the 

EPA has the responsibility to establish 

a CAA section 111(d) plan for that area 

of Indian country where affected 

sources are located unless the tribe on 

whose lands an affected source (or 

sources) is located seeks and obtains 

authority from the EPA to establish a 

plan itself, pursuant to the Tribal 

Authority Rule.272 The agency is 

soliciting comment on aspects of such 

CAA section 111(d) plans, as described 

in Section V.D of this preamble. 

This section is organized into six 

parts. First, we discuss the types of 

plans that we propose states could 

submit. Second, we address timing for 

plan implementation and achievement 

of state emission performance goals for 

affected EGUs. Third, we discuss the 

proposed state plan approvability 

criteria. Fourth, we summarize the 

proposed components of an approvable 

state plan. Fifth, we address the 

proposed process and timing for 

submittal of state plans. Sixth, we 

identify several key considerations for 

states in developing and implementing 

plans, including: Affected entities with 

obligations under a plan; treatment of 

existing state programs; incorporation of 

renewable energy (RE) and demand-side 

energy efficiency (EE) programs in 

certain plans; quantification, 

monitoring, and verification of RE and 

demand-side EE measures; reporting 

and recordkeeping for affected entities; 

treatment of interstate effects; and 

projection of emission performance. 

Finally, we discuss a number of 

additional factors that could help states 

meet their CO2 emission performance 

goals, and we note certain resources that 

are available to facilitate plan 

development and implementation. 

Additional discussion of some of the 

topics covered in this section can be 

found in the State Plan Considerations 

TSD and Projecting EGU CO2 Emission 

Performance in State Plans TSD, both of 

which are in the rulemaking docket. 

B. Approach 

In this action, the EPA is proposing 

emission guidelines in the form of statespecific CO2 emission performance 

goals. In addition, the EPA is proposing 

guidelines for states to follow in 

developing plans to establish and 

implement CO2 emission standards for 

affected EGUs. The proposed plan 

guidelines include four general plan 

approvability criteria, twelve required 

components for a state plan to be 

approvable, the process and timing for 

state plan submittal and review, and the 

process and timing for demonstrating 

achievement of the CO2 goals. These are 

described below. 

The EPA recognizes that each state 

has different state policy 

considerations—including varying 

emission reduction opportunities and 

existing state programs and measures— 

and that the characteristics of the 

electricity system in each state (e.g., 

utility regulatory structure, generation 

mix, electricity demand) also differ. The 

agency also anticipates—and supports— 

states’ commitments to a wide range of 

policy preferences that could 

encompass those of states like 

Kentucky, West Virginia and Wyoming 

seeking to continue to feature significant 

reliance on coal-based generation; states 

like Minnesota, Colorado, California and 

the nine RGGI states seeking to build on 

actions and policies they have already 

undertaken; and states like Washington 

and Oregon seeking to integrate 

sustainable forestry and renewable 

energy strategies. The proposed plan 

guidelines provide states with options 

for establishing emission standards in a 

manner that accommodates a diverse 

range of state approaches. Each state 

will have significant flexibility to 

determine how to best achieve its CO2

goals in light of its specific 

circumstances, including addressing 

concerns particular to the state, such as 

employment transition issues, as it 

designs and implements its plan over 

multiple years. As an example, the RGGI 

states’ implementation of their massbased emission budget trading program 

raises proceeds through allowance 

auctions and uses those proceeds to 

advance programs promoting and 

expanding end-use energy efficiency. 

States could address analogous 

priorities, such as employment 

transition, through a similar 

mechanism. 

The proposed plan guidelines would 

also allow states to collaborate and to 

develop plans that provide for 

demonstration of emission performance 

on a multi-state basis, in recognition of 

the fact that electricity is transmitted 

across state lines, and that state 

measures may impact, and may be 

explicitly designed to reduce, regional 

EGU CO2 emissions. The EPA also 

recognizes that multi-state collaboration 

would likely offer lower-cost 

approaches to achieving CO2 emission 

reductions. With this in mind, we are 

proposing to provide states with 

additional time to submit complete 

plans if they do so as part of a multistate plan, and we solicit comment on 

other potential mechanisms for fostering 

multi-state collaboration. 

1. State Plan Approaches 

a. Overview 

Although state CAA section 111(d) 

plans must assure that the emission 

performance level is achieved through 


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273 In the case of a utility-driven portfolio 

approach, the vertically integrated electric utility 

implementing portfolio measures is also the owner 

and operator of affected EGUs. 

274A state-driven portfolio approach is more 

likely in states that have instituted electricity sector 

restructuring, where electric utilities have typically 

been required by states to divest electric generating 

assets. 

reductions at the affected sources, we 

believe that different types of state plans 

could be constructed that make use of 

the diversity of measures available to 

achieve CO2 emission reductions. Based 

on the EPA’s outreach efforts, it is clear 

that states are considering different 

types of plans. 

Three important issues in the design 

of state plans include: (1) Whether the 

plan should require the affected EGUs to 

be subject to emission limits that assure 

that the emission performance level is 

achieved, or instead, whether the plan 

could rely on measures, such as 

renewable energy (RE) or demand-side 

energy-efficiency (EE), to assure the 

achievement of part of the emission 

performance level; (2) whether the 

responsibility for all of the measures 

other than emission limits should fall 

on the affected EGUs, or, instead, could 

fall on entities other than affected EGUs; 

and (3) whether the fact that requiring 

all measures relied on to achieve the 

emission performance level to be 

included in the state plan renders those 

measures federally enforceable. These 

issues and the EPA’s proposed approach 

are addressed in detail in the sections 

that follow. 

The EPA is proposing that all 

measures relied on to achieve the 

emission performance level be included 

in the state plan, and that inclusion in 

the state plan renders those measures 

federally enforceable. 

In light of current state programs, and 

of stakeholder expressions of concerns 

over the above-noted issues, including 

legal enforcement considerations, with 

respect to those programs, the EPA is 

proposing to authorize states either to 

submit plans that hold the affected 

EGUs fully and solely responsible for 

achieving the emission performance 

level, or to submit plans that rely in part 

on measures imposed on entities other 

than affected EGUs to achieve at least 

part of that level, as well as on measures 

imposed on affected EGUs to achieve 

the balance of that level. The EPA 

requests comment on this proposed 

approach, as opposed to the approach 

under which state plans simply would 

be required to hold the affected EGUs 

fully and solely responsible for 

achieving the emission performance 

level. 

In addition, the EPA is soliciting 

comment on several other types of state 

plans that may assure the requisite level 

of emission performance without 

rendering certain types of measures 

federally enforceable and that limit the 

obligations of the affected EGUs. 

b. Portfolio Approach 

In assessing the types of state plans to 

authorize, the EPA reviewed existing 

state programs that reduce CO2

emissions from fossil fuel-fired power 

plants. Existing state programs are 

particularly informative for this purpose 

in light of the fact that CAA section 

111(d) gives states the primary 

responsibility for designing their own 

state plans for submission to the EPA. 

Many of these existing state programs, 

as summarized above, include measures 

such as renewable energy (RE) and 

demand-side energy efficiency (EE) 

programs, which impose responsibilities 

on a range of entities, including state 

agencies, for assuring implementation of 

actions that result in reduced utilization 

of, and therefore reduced emissions 

from, fossil fuel-fired EGUs, and do not 

impose legal responsibilities for those 

emission reductions on the EGUs 

themselves. 

In addition, during the EPA’s 

extensive outreach efforts, many 

stakeholders expressed concern over the 

extent of responsibility that fossil fuelfired EGUs would be required to bear for 

the required emission reductions, in 

particular, those associated with RE and 

demand-side EE measures. These 

stakeholders recommended that the EPA 

authorize states to achieve emission 

reductions from RE and demand-side EE 

measures by imposing requirements on 

entities other than fossil fuel-fired 

EGUs, and without imposing legal 

responsibility for these emission 

reductions on those EGUs. 

Accordingly, the EPA is proposing to 

authorize a state plan to adopt what we 

refer to as a ‘‘portfolio approach,’’ in 

which the plan would include emission 

limits for affected EGUs along with 

other enforceable measures, such as RE 

and demand-side EE measures, that 

reduce CO2 emissions from affected 

EGUs. Under this approach, it would be 

all of the measures combined that 

would be designed to achieve the 

required emission performance level for 

affected EGUs as expressed in the state 

goal. Under this approach, the emission 

limits enforceable against the affected 

EGUs would not, on their own, assure, 

or be required to assure, achievement of 

the emission performance level. Rather, 

the state plan would include measures 

enforceable against other entities that 

support reduced generation by, and 

therefore CO2 emission reductions from, 

the affected EGUs. As noted, these other 

measures would be federally 

enforceable because they would be 

included in the state plan. A portfolio 

approach could be used for state plans 

that establish the emission performance 

level on either an emission rate basis or 

a mass emissions basis. 

In addition, a portfolio approach 

could either be what we refer to as 

‘‘utility-driven’’ or ‘‘state-driven,’’ 

depending on the utility regulatory 

structure in a state. Under a utilitydriven approach, a state plan may 

include, for example, measures 

implemented consistent with a utility 

integrated resource plan, including both 

measures that directly apply to affected 

EGUs (e.g., repowering or retirement of 

one or more EGUs) as well as RE and 

demand-side EE measures that avoid 

EGU CO2 emissions.273 Under a statedriven approach, the measures in a state 

plan would include emission standards 

for affected EGUs, as well as 

requirements that apply to entities other 

than affected EGUs, for example, 

renewable portfolio standards (RPS) or 

end-use energy efficiency resource 

standards (EERS), both of which often 

apply to electric distribution utilities.274

c. Obligations on Affected EGUs 

The EPA is proposing to authorize 

state plans to adopt the portfolio 

approach and is proposing to interpret 

the CAA as allowing that approach, as 

described in more detail below. CAA 

section 111(d)(1) would certainly allow 

state plans to require the affected EGUs 

to be the sole entities legally responsible 

for achieving the emission performance 

level. The EPA is also soliciting 

comment on whether it can reasonably 

interpret CAA section 111(d)(1) to allow 

states to adopt plans that require EGUs 

and other entities to be legally 

responsible for actions required under 

the plan that will, in aggregate, achieve 

the emission performance level. 

We note that some existing state 

programs, such as RGGI in the 

northeastern states, do impose the 

ultimate responsibility on fossil fuelfired EGUs to achieve the required 

emission reductions, but are also 

designed to work either concurrently, or 

in an integrated fashion, with RE and 

demand-side EE programs that reduce 

the cost of meeting those emission 

limitations. These existing programs 

offer a possible precedent for another 

type of CAA section 111(d) state plan. 

Such a plan approach could rely on CO2

emission standards enforceable against 

affected EGUs—whether in the form of 


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emission rate or mass limits—to ensure 

achievement of the required emission 

performance level, but also include 

enforceable or complementary RE and 

demand-side EE measures that lower 

cost and otherwise facilitate EGU 

emission reductions. Depending on the 

type of plan, these RE and demand-side 

EE measures could either be enforceable 

components of the plan (that is, the 

states could require affected EGUs or 

other affected entities to invest in RE or 

in demand-side EE programs) or be 

complementary to the plan. In this 

manner, RE and demand-side EE 

measures could be a major component 

of a state’s overall strategy for reducing 

EGU CO2 emissions at a reasonable cost. 

It should be noted that state plan 

approaches that impose legal 

responsibility on the affected EGUs to 

achieve the full level of required 

emission performance could incorporate 

RE and demand-side EE measures 

regardless of whether the emission 

standards that those plans apply to the 

affected EGUs take the form of an 

emission rate or a mass limit. Plans with 

rate-based emission limits could 

incorporate enforceable RE and 

demand-side EE measures by adjusting 

an EGU’s CO2 emission rate when 

demonstrating compliance through 

either an administrative adjustment by 

the state or use of a tradable credit 

approach. (These actions would need to 

be enforceable components of a state 

plan to facilitate EGU compliance with 

emission rate limits and ensure that 

actions are properly quantified, 

monitored, and verified.) A state plan 

that imposes a mass limit on affected 

EGUs that is sufficiently stringent to 

achieve the emission performance level 

would not need to include RE or 

demand-side EE measures as an 

enforceable component of the plan to 

assure the achievement of that 

performance level. The mass limit itself 

would suffice. However, the state may 

wish to implement RE and demand-side 

EE measures as a complement to the 

plan to support achievement of the mass 

limit at lesser cost. 

d. Federal Enforceability 

Another concern expressed by some 

stakeholders is that including RE and 

demand-side EE measures in state plans 

would render those measures federally 

enforceable and thereby extend federal 

presence into areas that, to date, largely 

have been the exclusive preserve of the 

state and, in particular, state public 

utility commissions and the electric 

utility companies they regulate. These 

stakeholders suggest that states could 

rely on RE and demand-side EE 

programs as complementary measures to 

reduce costs for, and otherwise 

facilitate, EGU emission limits without 

including those measures in the CAA 

section 111(d) state plan. Under this 

suggested approach, the EGU emission 

limits would be federally enforceable, 

but RE and demand-side EE measures 

would serve as complementary 

measures and would not be enforceable 

under federal law; instead, they would 

remain enforceable under state law. 

According to stakeholders, those types 

of state programs, particularly because 

they are well-established, can be 

expected to achieve their intended 

results. Thus, they suggest that the 

states could conclude that those RE and 

demand-side EE measures would be 

beneficial in assuring the achievement 

of the required emission performance 

level by the affected EGUs specified in 

the CAA section 111(d) state plan, even 

without including those measures in the 

plan. 

e. Plans With State Commitments 

As another vehicle for approving CAA 

section 111(d) plans for states that wish 

to rely on state RE and demand-side EE 

programs but do not wish to include 

those programs in their state plans, the 

EPA requests comment on what we refer 

to as a ‘‘state commitment approach.’’ 

This approach differs from the proposed 

portfolio approach, described above, in 

one major way: Under the state 

commitment approach, the state 

requirements for entities other than 

affected EGUs would not be components 

of the state plan and therefore would 

not be federally enforceable. Instead, the 

state plan would include an enforceable 

commitment by the state itself to 

implement state-enforceable (but not 

federally enforceable) measures that 

would achieve a specified portion of the 

required emission performance level on 

behalf of affected EGUs. The agency 

requests comment on the 

appropriateness of this approach. The 

agency also requests comment on the 

policy ramifications of the following: 

Under this approach, the state programs 

upon which the state bases its 

commitment may, in turn, rely on 

compliance by third parties, and if those 

state programs fail to achieve the 

expected emission reductions, the state 

could be subject to challenges— 

including by citizen groups—for 

violating CAA requirements and, as a 

result, could be held liable for CAA 

penalties. 

We also solicit comment on a 

variation of this state commitment plan 

approach that is also designed to 

address stakeholder concerns, noted 

above, about imposing sole legal 

responsibility on affected EGUs for 

achieving the emission performance 

level. With this variation, the state plan 

would in effect shift a portion of that 

responsibility to the state, in the 

following manner: The state plan would 

impose the full responsibility for 

achieving the emission performance 

level on the affected EGUs, but the state 

would credit the EGUs with the amount 

of emission reductions expected to be 

achieved from, for example, RE or 

demand-side EE measures. The state 

would then assume responsibility for 

that credited amount of emission 

reductions in the same manner as the 

state commitment plan approach 

discussed above. We solicit comment on 

whether, if the EPA were to conclude 

that CAA section 111(d) requires state 

plans to include standards of 

performance applicable to affected 

EGUs that achieve the emission 

performance level, this type of state 

plan would meet that requirement while 

also assuring those EGUs an important 

measure of support. 

f. Legal Issues 

The EPA is proposing to interpret the 

relevant provisions in CAA section 111 

to authorize state plans that achieve 

emissions reductions from affected 

EGUs by means of the portfolio 

approach. CAA section 111(d)(1) 

requires each state to submit a plan that 

‘‘(A) establishes standards of 

performance for any existing source [for 

certain air pollutants] . . . and (B) 

provides for the implementation and 

enforcement of such standards of 

performance.’’ CAA section 111(a)(1) 

defines a ‘‘standard of performance’’ as 

‘‘a standard for emissions of air 

pollutants which reflects the degree of 

emission limitation achievable through 

the application of the best system of 

emission reduction . . . adequately 

demonstrated.’’ 

These provisions make clear that 

emission limits that are enforceable 

against affected EGUs appropriately 

belong in state plans because they 

clearly are ‘‘standards of performance.’’ 

However, the terms of CAA section 

111(d)(1) do not explicitly address 

whether, in addition to emission limits 

on affected EGUs, state plans may 

include other measures for achieving 

the emission performance level. Nor do 

they address whether entities other than 

affected EGUs may be subject to 

requirements that contribute to reducing 

EGU emissions. Under the U.S. 

Supreme Court’s 1984 decision in 

Chevron U.S.A. Inc. v. NRDC, where the 

statute leaves a gap, the agency has 

discretion to fashion an interpretation 


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275Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 

842–44 (1984). 

that is a reasonable construction of the 

statute.275

The EPA is proposing to interpret the 

phrases ‘‘standards of performance for 

any existing source’’ and ‘‘the 

implementation and enforcement of 

such standards of performance’’ to 

encompass and allow the various 

components of the portfolio approach. 

To the extent that a portfolio approach 

contains measures that are not standards 

of performance or do not implement or 

enforce such standards, the EPA is 

proposing to interpret CAA section 111 

as allowing state CAA section 111(d) 

plans to include measures that are 

neither standards of performance nor 

measures that implement or enforce 

those standards, provided that the 

measures reduce CO2 emissions from 

affected sources. These measures would 

also be federally enforceable if included 

in an approved plan. 

The EPA’s proposed interpretation is 

based, in part, on CAA section 111(d)’s 

requirement that states set performance 

standards ‘‘for’’ affected sources. 

Although ‘‘for’’ could be read as 

meaning that the standards must apply 

to affected sources, ‘‘for’’ is also 

reasonably interpreted to have a more 

capacious meaning: Standards (such as 

EE and RE standards) are reasonably 

considered to be ‘‘for’’ affected sources 

if they would have an effect on affected 

sources by, for example, causing 

reductions in affected EGUs’ CO2

emissions by decreasing the amount of 

generation needed from affected EGUs. 

Under this interpretation, and 

depending on the specific provisions in 

the state plan, renewable energy and 

demand-side energy efficiency 

requirements would be ‘‘for’’ fossil fuelfired EGUs where such standards result 

in reduced CO2 emissions from fossil 

fuel-fired EGUs, even if the standards do 

not apply directly to fossil fuel-fired 

EGUs. 

The EPA also requests comment on 

another approach: Whether ‘‘standards 

of performance for [affected sources]’’ is 

reasonably read to include the emission 

performance level (i.e., the state goal) on 

grounds that the level is ‘‘a standard for 

emissions’’ because it is in the nature of 

a requirement that concerns emissions 

and it is ‘‘for’’ the affected sources 

because it helps determine their 

obligations under the plan. 

Moreover, where the specific 

measures in the portfolio approach are 

not themselves a ‘‘standard of 

performance,’’ state plans may include 

measures that implement or enforce a 

standard of performance. For example, 

if the state’s plan achieves the emission 

performance level through rate-based 

emission limits applicable to the 

affected sources, coupled with a 

crediting mechanism for RE and 

demand-side EE measures, we propose 

that RE and demand-side EE measures 

may be included in the plan as 

‘‘implement[ing]’’ measures because 

they facilitate the sources’ compliance 

with their standards of performance. We 

solicit comment on the extent to which 

measures such as RE and demand-side 

EE may be considered ‘‘implement[ing]’’ 

measures in state plans if they are not 

directly tied to emission reductions that 

affected sources are required to make 

through emission limits, and if they are 

requirements on entities other than the 

affected sources. In addition, the EPA 

proposes to interpret CAA section 

111(d)(1) to allow state plans to include 

components of the portfolio approach 

that are measures that would reduce 

emissions from affected sources, even if 

those measures are neither ‘‘standards of 

performance for existing sources’’ nor 

measures ‘‘for the implementation and 

enforcement of such standards of 

performance.’’ There is no specific 

language in CAA section 111(d) or 

elsewhere in the Act that prohibits 

states from including measures other 

than performance standards and 

implementation and enforcement 

measures, provided that they reduce 

emissions from affected EGUs. 

This interpretation is consistent with 

the principle of cooperative federalism, 

which is one of the foundational 

principles of the Clean Air Act and 

which supports providing flexibility to 

states to meet environmental goals 

(provided minimum CAA statutory 

requirements are met). This general 

principle, especially when combined 

with the statutory directive that CAA 

section 111(d) regulations shall 

establish procedures ‘‘similar to that 

provided by section 110,’’ supports an 

interpretation of CAA section 111(d) 

that allows states sufficient flexibility in 

meeting the state goal set under CAA 

section 111(d) to include in their CAA 

section 111(d) plans other measures 

(i.e., measures that are neither 

performance standards nor measures 

that enforce or implement performance 

standards). The EPA solicits comment 

on all aspects of its proposed 

interpretation that states have this 

flexibility in selecting measures for their 

state plans under CAA section 111(d). 

An alternative interpretation of CAA 

section 111(d)(1) would suggest that the 

responsibility to achieve the state’s 

required emission performance level 

must be assigned solely to affected 

EGUs. As described elsewhere in this 

preamble, there are a number of statelevel CO2 programs that take this 

approach while still taking advantage of 

low-cost reductions from RE and 

demand-side EE through the use of 

complementary measures. This 

alternative interpretation would be 

based on, for example: A determination 

that CAA section 111(d)(1) must be read 

as precluding a state plan from 

including measures that are neither 

standards of performance nor measures 

for the implementation or enforcement 

of such standards; an interpretation that 

the state’s obligation to set performance 

standards ‘‘for’’ existing sources means 

that the standards must apply to 

affected EGUs and not to other entities; 

and an interpretation that measures ‘‘for 

the implementation and enforcement of 

such performance standards’’ do not 

include measures that are not intended 

or designed to assist affected EGUs in 

meeting the performance standards. The 

EPA requests comment on whether it 

must adopt this alternative 

interpretation. If so, the EPA also takes 

comment on whether there is a way, 

nonetheless, to allow states to rely on 

the portfolio approach to some extent 

and/or for some period of time. 

We request comment on all of the 

interpretations discussed in this section 

generally, and on all legal issues under 

CAA section 111(d)(1) with respect to 

what measures can be included in a 

state plan and what entities must be 

legally responsible for meeting those 

measures. 

g. Ongoing Applicability of CAA 

Section 111(d) State Plan 

The EPA is proposing that an existing 

source that becomes subject to 

requirements under CAA section 111(d) 

will continue to be subject to those 

requirements even after it undertakes a 

modification or reconstruction. Under 

this interpretation, a modified or 

reconstructed source would be subject 

to both (1) the CAA section 111(d) 

requirements that it had previously been 

subject to and (2) the modified source or 

reconstructed source standard being 

promulgated under CAA section 111(b) 

simultaneously with this rulemaking. It 

should be noted that this proposal 

applies to any existing source subject to 

any CAA section 111(d) plan, and not 

only existing sources subject to the CAA 

section 111(d) plans promulgated under 

this rulemaking. 

As noted above, a ‘‘new source’’ is 

defined under CAA section 111(a)(2) as 

‘‘any stationary source, the construction 

or modification of which is commenced 

after,’’ in general, a proposed or final 

CAA section 111(b) rule becomes 

applicable to that source; and under 


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section 111(a)(6), an ‘‘existing source’’ is 

defined as ‘‘any stationary source other 

than a new source.’’ Under these 

definitions, an ‘‘existing source’’ that 

commences construction of a 

modification or reconstruction after the 

EPA has proposed or finalized a CAA 

section 111(b) standard of performance 

applicable to it, becomes a ‘‘new 

source.’’ However, CAA section 111(d) 

is silent on whether requirements 

imposed under a CAA section 111(d) 

plan continue for a source that ceases to 

be an existing source because it 

modifies or reconstructs. Specifically, 

CAA section 111(d)(1) provides that 

‘‘each State shall submit to the 

Administrator a state plan which (A) 

‘‘establishes standards of performance 

for any existing source’’ but does not say 

whether, once the EPA has approved a 

state plan that establishes a standard of 

performance for a given source, that 

standard is lifted if the source ceases to 

be an existing source. Similarly, no 

other provisions of CAA section 111 

address whether the imposition of a 

CAA section 111(b) standard on a 

modified or reconstructed source ends 

the source’s obligation to meet any 

applicable CAA section 111(d) 

requirements. 

Because CAA section 111(d) does not 

address whether an existing source that 

is subject to a CAA section 111(d) 

program remains subject to that program 

even after it modifies or reconstructs, 

the EPA has authority to provide a 

reasonable interpretation, under the 

Supreme Court’s decision in Chevron 

U.S.A. Inc. v. NRDC, 467 U.S. 837, 842– 

844 (1984). The EPA’s interpretation is 

that under these circumstances, the 

source remains subject to the CAA 

section 111(d) plan, for two reasons. 

The first is to assure the integrity of the 

CAA section 111(d) plan. The EPA 

believes that many states will develop 

integrated plans that include all of their 

EGUs, such as rate- or mass-based 

trading programs. Uncertainty about 

whether units would remain in the 

program could be very disruptive to the 

operation of the program. The second 

reason is to avoid creating incentives for 

sources to seek to avoid their obligations 

under a CAA section 111(d) plan by 

undertaking modifications. The EPA is 

concerned that owners or operators of 

units might have incentives to modify 

purely because of potential 

discrepancies in the stringency of the 

two programs, which would undermine 

the emission reduction goals of CAA 

section 111(d). 

The EPA invites comments on this 

interpretation of CAA section 111(d)(1), 

including whether this interpretation is 

supported by the statutory text and 

whether this interpretation is sensible 

policy and will further the goals of the 

statute. It should be noted that this 

interpretation is severable from the rest 

of this rulemaking, so that if the EPA 

revises this interpretation in the final 

rule or if the EPA adopts this 

interpretation in the final rule but it is 

invalidated by a Court, there would be 

no effect on the rest of this rulemaking. 

2. Timing for Implementation and 

Achievement of Goals 

This section describes proposed state 

plan requirements related to the timing 

of achieving emission performance 

goals, including performance 

demonstrations, performance periods, 

and interim progress milestones. 

As previously discussed, the goals are 

derived from application of four 

‘‘building blocks.’’ The EPA has based 

the application of some of these 

measures to reduce CO2 emissions, 

particularly blocks 3 (expansion of 

cleaner generating capacity) and 4 

(increasing demand-side energy 

efficiency), on forward-looking, longerterm assumptions. For example, the 

EPA expects technologies to reduce 

carbon emissions to more fully develop 

over time and acknowledges the 

cumulative effects of implementation of 

EE programs and addition of RE 

generating capacity over time. 

Therefore, the EPA is not proposing to 

require each state to meet its full, final 

goal immediately, but rather to meet it 

by 2030. The EPA realizes, however, 

that states can achieve emission 

reductions from those and other 

measures in the short-term. Therefore, 

the EPA is proposing that states begin 

meeting interim goals, beginning in 

2020. The EPA also believes that timing 

flexibility in implementing measures 

provides significant benefits that allow 

states to develop plans that will help 

states achieve a number of goals, 

including: Reducing cost, addressing 

reliability concerns, and addressing 

concerns about stranded assets. 

Therefore, the EPA is also proposing to 

allow states flexibility to define the 

trajectory of emission performance 

between 2020 and 2029, as long as the 

interim emission performance level is 

met on a 10-year average or cumulative 

basis and the 2030 emission 

performance level is achieved. 

Section VIII.B.1.a of this preamble 

provides an overview of the proposals 

for state plan performance 

demonstrations and timing of emission 

reductions. Subsequent subsections 

include proposals for the start date for 

the interim goal performance period, the 

duration of the performance periods for 

the final and interim goals, interim 

progress milestone requirements, 

consequences if actual emission 

performance does not meet the state 

goal, and out-year requirements for 

states to maintain CO2 emission 

performance levels over time consistent 

with the final goal. In Section VIII.B.2.f 

of this preamble, the agency also 

requests comment on alternative 

requirements aimed at continued 

emission performance improvement 

after 2029. In Section VIII.B.2.g of this 

preamble, the EPA proposes flexibility 

for states to change from mass-based to 

rate-based goals in different 

performance periods and, in Section 

VIII.B.2.h, we solicit comment on 

planning requirements that match the 

option of alternative, less stringent state 

goals. 

a. Performance Demonstrations and 

Timing of Emission Reductions 

As described previously, the agency is 

proposing final state-specific goals 

(specified in Table 8) that represent 

emission rates to be achieved by 2030, 

as well as interim goals, to be achieved 

on average over the 10-year period from 

2020–2029. The agency is also 

proposing that emission performance 

levels consistent with the final statespecific goals be maintained after 2030. 

This relatively long planning and 

implementation period provides states 

with substantial flexibility regarding 

methods and timing of achieving 

emission reductions. States may wish to 

make adjustments to their 

implementation approaches along the 

way, or as conditions change may need 

to make adjustments to ensure that their 

plans achieve the goals as intended. As 

a result, the agency envisions that the 

EPA, states, and affected entities will 

have an ongoing relationship in the 

course of implementing this program. 

The EPA proposes that a state plan 

must demonstrate projected 

achievement of the emission 

performance levels in the plan, and 

these emission performance levels must 

be equivalent to or better than the 

interim and final goals established by 

the EPA. Specifically, the state plan 

must demonstrate that the projected 

emission performance of affected EGUs 

in the state will be equivalent to or 

better than the applicable interim goal 

during the 2020–2029 period, and 

equivalent to or better than the 

applicable final goal during the year 

2030. The state plan must identify 

requirements that continue to apply 

after 2030 and are likely to maintain 

continued emission performance by 

affected EGUs that meets the final goal; 

however, quantitative projections of 

emission performance by affected EGUs 


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276The 2020–2029 interim goal is expressed as a 

10-year average emission rate to provide states with 

flexibility in designing their plans. Due to the 

potential for continued end-use energy efficiency 

improvements, the 2029 four-building-block BSERbased level is a more stringent level than the 2020– 

2029 average four-building-block BSER-based level. 

The purpose of the final goal is to ensure that each 

state ultimately achieves the emission performance 

level for affected EGUs that is achievable by 2029. 

Without the final goal, it is possible that a state 

could achieve the 2020–2029 interim goal but not 

achieve the 2030 final goal. 

277The start date for a plan performance period 

must match the start date of the corresponding state 

emission performance goal. If a start date other than 

January 2020 were selected, the EPA would 

recompute the state goals consistent with the 

selected start date. 

278Source: NERC, 2008–2012 Generating Unit 

Statistical Brochure. 

beyond 2030 would not be required by 

this rule under the proposed approach. 

Instead, the EPA proposes that the state 

plan would be considered to provide for 

maintenance of emission performance 

consistent with the final goal if the plan 

measures used to demonstrate 

achievement of the final goal by 2030 

will continue in force and not sunset. 

In addition to demonstrating that 

projected plan performance will meet 

the interim and final state goals, the 

EPA proposes that state plans must 

contain requirements for tracking actual 

plan performance during 

implementation. For plans that do not 

include enforceable requirements for 

affected EGUs that ensure achievement 

of the full level of required emission 

performance and interim progress, the 

state plans would be required to include 

periodic program implementation 

milestones and emission performance 

checks, and include corrective measures 

to be implemented if mid-course 

corrections are necessary. The state plan 

would provide for continued tracking of 

emission performance after 2030, and 

for corrective measures if the emission 

performance of affected EGUs in the 

state did not continue to meet the 2030 

final goal during any three-year 

performance period. 

The rationale for this approach is that 

it would ensure that states design their 

plans in a way that considers both the 

interim and final goals. If only the 

interim goal were considered, a state 

plan might not be sufficient to achieve 

the final goal.276

The agency requests comment on a 

second option in which, in addition to 

submitting a plan demonstrating 

emission performance through 2030, 

states would be required to make a 

second submittal in 2025 showing 

whether their plan measures would 

maintain the final-goal level of emission 

performance over time (as further 

described below). If not, the state 

submittal would be required to 

strengthen or add to measures in the 

state plan to the extent necessary to 

maintain that level of performance over 

time. 

The EPA also requests comment on 

whether 2025, or an earlier or later year, 

would be the optimal year for a second 

plan submittal under the second option. 

b. Start Date for Performance Period for 

Interim Goal 

A performance period is a period for 

which the state plan must demonstrate 

that the required emission performance 

level will be met. The EPA proposes a 

start date of January 1, 2020, for the 

interim goal plan performance 

period.277 This date would be the 

beginning of the 10-year period for 

which a state must demonstrate that the 

projected emission performance level of 

affected EGUs in the state, on average, 

will be equivalent to or better than the 

applicable interim goal. The agency 

generally requests comment on the 

appropriate start date and rationale. 

In considering the start date, it is 

relevant to consider the due dates for 

state plan submittals and the amount of 

time available for program 

implementation by the start date. 

January 2020 is 3.5 years from the 

proposed June 2016 deadline for initial 

plan submittals, 2.5 years from the 

proposed June 2017 extended deadline 

for complete plans from states not 

participating in a multi-state plan, and 

1.5 years from the proposed June 2018 

extended deadline for complete plans 

from states participating in a multi-state 

plan. The EPA suggests that affected 

entities may have greater lead time for 

compliance than might be implied by 

the plan submittal dates referenced 

above. Affected entities will have 

knowledge of state requirements as they 

are adopted, and the state must adopt 

rules and requirements in advance of 

submitting its complete plan to the EPA. 

Also, as explained in detail in 

subsection c, states may choose a 

different emission performance 

improvement trajectory from that which 

the EPA assumes for purposes of 

calculating state goals, achieving lesser 

levels of performance in early years and 

more in later years, provided, of course, 

that the interim 10-year average 

requirement is met. 

The EPA proposes that a 2020 start 

date for the interim goal plan 

performance period is achievable in 

light of the following additional 

considerations. First, existing state 

programs will play a role in helping to 

achieve this rule’s proposed emission 

performance levels. Second, in advance 

of this proposal, many states already 

were contemplating design of strategies 

that would achieve CO2 emission 

reductions equivalent to those that 

could be required by CAA section 

111(d) emission guidelines. Third, for 

inclusion in the building blocks, the 

EPA considered only those emission 

abatement measures that are technically 

feasible and broadly applicable, and can 

provide reductions in CO2 emissions 

from affected EGUs at reasonable cost. 

For example, the EPA expects that 

many EGUs will meet their 

requirements in part by implementing 

heat rate improvements, and those 

actions may be undertaken promptly. 

The plant operations and maintenance 

(O&M) and engineering solutions used 

to improve heat rates at existing EGUs 

have long been commercially available 

and have been implemented at EGUs for 

many years. Further, the relatively 

modest capital costs (average $100/kW) 

and significant fuel savings associated 

with a suite of heat rate improvement 

(HRI) methods result in this measure 

being a low-cost approach to reducing 

CO2 emissions from existing EGUs. HRI 

‘‘best practices’’ (e.g., installation of 

modern control systems, operator 

training, smart soot blowing) are the 

least-cost HRI methods and can be 

applied quickly, without lengthy EGU 

outages. The somewhat more costly HRI 

‘‘upgrades’’ (e.g., steam turbine upgrade, 

boiler draft fan/driver upgrade) may 

require modest EGU outages to 

implement, but have also been applied 

on numerous EGUs to improve or 

maintain performance. Drawing on the 

power sector’s extensive experience 

with HRI methods, and the many 

existing supply chains already 

supporting these methods, the EPA 

expects that it would be feasible to 

implement HRI projects (i.e., building 

block 1) by 2020. 

Dispatch changes, which are largely 

driven by the variable cost of operating 

a given EGU, occur on an hourly basis 

in the power sector. The average 

availability factor for NGCCs in the U.S. 

generally exceeds 85 percent, and can 

exceed 90 percent for selected 

groups.278 In addition, the existing 

natural gas pipeline and electricity 

transmission networks are already 

connected to every existing NGCC 

facility, and can support aggregate 

operation of the NGCC fleet at 70 

percent (or above) at the state level, or 

can be reasonably expected to do so in 

the time frame for compliance with this 

rule. Therefore, building block 2, which 

represents shifting of generation from 

steam fossil EGUs to existing NGCCs, is 

a viable method for providing CO2


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279For EGUs that produce both electric energy 

output and other useful energy output, there would 

also be a credit for non-electric output, expressed 

in MWh. 

emission reductions at existing EGUs by 

the 2020 compliance start date. 

Building Block 3 is based on shifting 

generation from affected fossil units to 

new renewable energy generating 

capacity, which is added over time, and 

new or preserved nuclear capacity, all of 

which is expected to be in place by 2020 

(see the GHG Abatement Measures TSD 

for more information). 

Finally, there is considerable 

experience with the states and the 

power sector in designing and 

implementing demand-side energy 

efficiency improvement strategies and 

programs. It is also well accepted that 

such improvements can achieve 

reductions in CO2 emissions from 

existing EGUs at a reasonable cost. 

Building block 4 represents a feasible 

pathway for reducing utilization of 

carbon-emitting EGUs by implementing 

improvements in demand-side energy 

efficiency. This building block is based 

on a ‘‘best practices’’ scenario where all 

states achieve a level of performance— 

matching a level achieved or committed 

to by twelve leading states—of 1.5 

percent annual incremental electricity 

savings as a percentage of retail sales. 

For the best practices scenario, all states 

achieve this level of performance no 

later than 2025, with leading states 

reaching this level sooner. Each state’s 

current level of performance is taken 

into account, with states achieving 

lower levels of performance being 

allowed more time to reach the best 

practice level. 

c. Duration of Performance Periods for 

Final and Interim Goals 

The EPA recognizes that a state’s 

circumstances and choice of emission 

reduction strategies may affect the 

timing of CO2 emission performance 

improvement within a multi-year 

planning period. States can be expected 

to select various combinations of 

measures and those measures may vary 

in the time needed to reach full 

implementation. The agency recognizes 

that certain emission reduction 

measures and programs (e.g., heat rate 

improvements) are generally easier to 

implement in the near term, while 

others (e.g., renewable portfolio 

standards, demand-side energy 

efficiency programs) may require several 

years to implement because of the time 

necessary to establish the proper 

infrastructure if a state does not already 

have such programs in place. Though 

some states have already implemented 

such programs that are achieving 

results, other states may have to 

establish them for the first time. New 

single and multi-state programs, as well 

as existing single and multi-state 

programs that are adding or revising 

measures, may need time for 

implementation to achieve the required 

level of emission performance. 

As described in Section VII of the 

preamble, the EPA is proposing statespecific CO2 emission performance 

goals in a multi-year format to provide 

states with flexibility for the timing of 

programs and measures that improve 

EGU emission performance, while 

ensuring an overall level of performance 

consistent with application of the BSER. 

Specifically, the agency is proposing the 

state-specific goals (shown in Table 8) 

which represent emission rates to be 

achieved by 2030 (final goal) and 

emission rates to be achieved on average 

over the 2020–2029 period (the interim 

goal). 

The EPA proposes the following as 

the preferred option for the final and 

interim goal performance periods. As 

further explained below, this option 

reflects three main objectives: (1) 

Provide states with timing flexibility 

during the interim goal period to 

accommodate differences in state 

adoption processes and types of state 

programs, (2) ensure that state plans are 

designed to achieve the final goal no 

later than 2030, and (3) provide 

flexibility for year-to-year variation in 

actual emission performance that may 

occur as the electricity system responds 

to economic fluctuations. 

Interim goal—Projected plan 

performance demonstration: To be 

approvable, a state plan must 

demonstrate that the emission 

performance of affected EGUs will meet 

the interim emission performance level 

on average over the 2020–2029 period. 

Interim goal—Actual plan 

performance check: In 2030, the 

emission performance of affected EGUs 

during the period 2020–2029 must be 

compared against the interim goal. (In 

addition, as described separately below, 

interim emission performance checks 

will occur during this 10-year period.) 

Final goal—Projected plan 

performance demonstration: To be 

approvable, a state plan must 

demonstrate that the emission 

performance of affected EGUs will meet 

the final emission performance level no 

later than 2030, on a single-year basis. 

Final goal—Actual plan performance 

check: Starting at the end of 2032, 

emission performance of affected EGUs 

must be compared against the final goal 

on a three-year rolling average basis 

(i.e., 2030–32, 2031–33, 2032–2034, 

etc.). 

This proposed approach provides a 

10-year performance period for the 

interim performance level. The 10-year 

period allows states flexibility for 

timing of program implementation as 

the state ramps up its programs to 

achieve the final performance level. 

Using the single year 2030 as the 

projected year for achievement of the 

final goal ensures that state plans are 

designed to achieve the final goal no 

later than 2030; providing a multi-year 

time frame for projected plan 

performance would inappropriately 

delay the requirement for a final-goal 

level of performance that the EPA’s 

analysis shows is achievable at the end 

of the 10-year interim ramp-up period. 

Using 2030 also avoids overlap with the 

interim goal performance period. The 

rolling three-year performance periods 

for measuring actual plan performance 

against the final goal performance level 

are proposed in light of year-to-year 

variability in economic and other 

factors, such as weather, that influence 

power system operation and affect EGU 

CO2 emissions. The choice of 2030– 

2032 avoids overlap with the 2020–2029 

interim goal performance period. 

For a rate-based plan, 2020–2029 

emission performance is an average CO2

emission rate for affected EGUs 

representing cumulative CO2 emissions 

for affected EGUs over the course of the 

10-year performance period divided by 

cumulative MWh energy output 279 from 

affected EGUs over the 10-year 

performance period, with rate 

adjustments for qualifying measures, 

such as end-use energy efficiency and 

renewable energy measures, as 

described in Section VIII.F.3. For a 

mass-based plan, 2020–2029 emission 

performance is total tons of CO2 emitted 

by affected EGUs over the 10-year 

performance period. 

The agency invites comment on this 

and other approaches to specifying 

performance periods for state plans. 

d. Program Implementation Milestones 

and Tracking of Emission Performance 

The EPA recognizes the importance of 

ensuring that, during the proposed 10- 

year performance period (2020–2029) 

for the interim goal, a state is making 

steady progress toward achieving the 

required level of emission performance. 

The EPA is proposing that certain types 

of state plans be required to have 

program implementation milestones to 

ensure interim progress, as well as 

periodic checks on overall emission 

performance leading to corrective 

measures if necessary. 

Some types of plans are ‘‘selfcorrecting’’ in that they inherently 


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would assure interim performance and 

full achievement of the state plan’s 

required level of emission performance 

through requirements that are 

enforceable against affected EGUs. One 

example is a state plan with a rate-based 

emission performance level that 

requires affected EGUs collectively to 

meet an emission rate consistent with 

the state’s required emission 

performance level, and allows EGUs to 

comply through an emission rate 

averaging system. Another example is a 

plan that includes measures or actions 

(e.g., emission limits that apply to 

affected EGUs and ensure full plan 

performance) that take effect 

automatically if the plan’s required 

emission performance level is not met, 

in accordance with a specified 

milestone. The EPA requests comment 

on whether there are other types of state 

plans that should be considered ‘‘selfcorrecting.’’ 

The EPA proposes that self-correcting 

plans need not contain interim 

milestones consisting of program 

implementation steps, because these 

state plans inherently require both 

interim progress and achievement of the 

full level of required emission 

performance in a manner that is 

federally enforceable against affected 

EGUs. Annual reporting of emission 

performance by the state, however, is 

required for all types of plans. 

For plans that are not self-correcting, 

the EPA proposes that the state plan 

must identify periodic program 

implementation milestones (e.g., start of 

an end-use energy efficiency program, 

retirement of an affected EGU, or 

increase in portfolio requirements under 

a renewable portfolio standard) that are 

appropriate to the programs and 

measures included in the plan. If, 

during plan implementation, a state 

were to miss program implementation 

milestones in its plan, it would need to 

report the delay to the EPA, explain the 

cause, and describe the steps the state 

will take to accelerate subsequent 

implementation to achieve the planned 

improvements in emission performance. 

Depending on the severity of delay and 

the explanation, the EPA could 

ultimately evaluate actions under CAA 

authorities to ensure timely program 

implementation. 

In addition, we propose that the state 

and the EPA would track state plan 

emission performance on an ongoing 

basis, with states reporting performance 

data to the EPA annually by July 1. 

During the interim performance period, 

beginning in 2022, the state would be 

required each year to include a 

comparison of emission performance 

achieved to performance projected in 

the state plan. Each comparison would 

cover the preceding two-year period. 

The EPA may also approve regular, 

periodic emission comparison checks 

with a different frequency or 

comparison period to reflect the design 

of a state’s programs (e.g., compliance 

periods for EGUs under an emission 

limit). 

A report and corrective measures 

would be required if an interim 

emission check showed that actual 

emission performance of affected 

entities was not within 10 percent of the 

performance projected in the state plan 

(i.e., for a rate-based plan, if the average 

emission rate of affected EGUs were 10 

percent higher than plan projections, or 

for a mass-based plan, if collective 

emissions of affected EGUs were 10 

percent higher than plan projections). In 

that event, the state would be required 

in its submission to explain reasons for 

the deviation (e.g., energy efficiency 

program not working as effectively as 

expected, prolonged extreme weather 

that had been unanticipated in 

electricity demand projections) and 

specify the corrective measures that will 

be taken to ensure that the required 

level of emission performance in the 

plan will be met. The state also would 

be required to implement those 

corrective measures as expeditiously as 

practical. 

The agency proposes that states be 

given a choice regarding when to adopt 

into regulation the corrective measures 

that the state plan identifies for 

implementation in the event that state 

plan performance is deficient. First, the 

state could adopt corrective measures 

into regulation prior to plan submittal in 

a manner that enables the state to 

implement the measures 

administratively, without further 

legislation or rulemaking, if a 

performance deficiency occurs during 

plan implementation. This would 

expedite implementation of corrective 

measures once a deficiency is 

discovered. Second, the state could elect 

to wait to adopt into regulation the 

corrective measures identified in the 

plan until after a plan performance 

deficiency is discovered. The EPA 

proposes this choice in recognition of 

the fact that it may be challenging for 

states to fully adopt corrective measures 

in advance to address the possibility 

that their plan will not perform as 

projected. However, if a state makes the 

latter choice, the EPA proposes that the 

state must report the reasons for 

deficient performance and must 

implement corrective measures if actual 

emission performance was inferior to 

projected performance by eight percent 

or more (rather than 10 percent or 

more). The reason for the lower 

percentage trigger is to identify a 

gradually developing deficiency in plan 

performance earlier in time. Legislative 

and/or regulatory action to adopt 

corrective measures after a deficiency is 

discovered will take significant time. 

State processes to activate corrective 

measures should be triggered earlier if 

corrective measures are not adopted in 

regulation and ready to implement. 

The EPA alternatively requests 

comment on whether states should be 

required to create legal authority and/or 

adopt regulations providing for 

corrective measures in developing the 

state plan. The agency requests 

comment generally on the conditions 

that should trigger corrective measure 

requirements. The agency also solicits 

comment on whether actual emission 

performance inferior to projected 

performance by ten percent (for plans 

with corrective measures adopted into 

regulation prior to complete plan 

submittal) is the appropriate trigger for 

requiring a state to report the reasons for 

deficient performance and to implement 

corrective measures. We are also 

soliciting comment on the range of five 

percent to fifteen percent. For plans 

without corrective measures adopted 

into regulation prior to complete plan 

submittal, the agency solicits comment 

on whether the proposed eight percent 

emission performance deviation trigger 

is appropriate. We also solicit comment 

on the range of five percent to ten 

percent. 

The EPA proposes that the state will 

be required to compare actual emission 

performance achieved during the entire 

10-year interim performance period (i.e., 

2020–2029) against the interim goal. As 

noted above, beginning after 2032, the 

EPA proposes that the state be required 

to compare actual emission performance 

achieved against the final goal on a 

rolling three-year average basis (e.g., 

2030–32, 2031–33, etc.). The EPA also 

requests comment on the milestone 

approach and emission performance 

checks outlined above in the context of 

the alternative 5-year performance 

period and the planning approach for 

alternative state goals, which is 

described below. 

e. Consequences if Actual Emission 

Performance Does Not Meet State Goal 

There are scenarios under which an 

approved state plan might fail to 

achieve a level of emission performance 

by affected EGUs that meets the state 

goal. Under some types of plans, a 

possible scenario is that despite 

successful plan implementation, 

emissions under the plan turn out to be 

higher than projected at the time of plan 


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280CAA section 411(b). 

281This is straightforward for plans with EGU 

emission limits that ensure the full level of 

performance required. For renewable energy 

programs, the agency suggests that the state could 

continue to require the renewable portfolio 

percentage level that was relied upon to 

demonstrate projected achievement of the final goal 

performance level in 2030. For plans that rely in 

part on end-use energy efficiency programs and 

measures, the EPA requests comment on what a 

state would need to require in its plan to show that 

performance will be maintained after 2030. End-use 

energy efficiency programs and measures often 

involve an annual energy savings requirement or 

goal, and some types require additional monetary 

expenditures each year to meet those savings 

requirements or goals. 

approval because actual economic 

conditions vary from economic 

assumptions used when projecting 

emission performance. State officials 

have raised the possibility that achieved 

emission performance might not meet 

projected performance if, for example, 

planned retirements of EGUs were 

postponed because severe weather 

produced greater-than-expected 

electricity generation needs. In addition, 

emissions could theoretically exceed 

projections because affected entities 

under a state plan did not fulfill their 

responsibilities, or because the state did 

not fulfill its responsibilities. 

The EPA believes that the emission 

guidelines should specify the 

consequences in the event that actual 

emission performance under a state plan 

does not meet the applicable interim 

goal in 2020–2029, or does not meet the 

applicable final goal in 2030–2032 or 

later, because CAA section 111(d) is not 

specific on this point. The agency 

requests comment on how the 

consequences should vary depending on 

the reasons for a deficiency in 

performance. 

Specifically, the agency requests 

comment on whether consequences 

should include the triggering of 

corrective measures in the state plan, or 

plan revisions to adjust requirements or 

add new measures. The agency also 

requests comment on whether corrective 

measures, in addition to ensuring future 

achievement of the state goal, should be 

required to achieve additional emission 

reductions to offset any emission 

performance deficiency that occurred 

during a performance period for the 

interim or final goal. This concept has 

been applied, for example, in the Acid 

Rain Program under Title IV of the CAA; 

a source that has sulfur dioxide 

emissions exceeding the emission 

allowances that it holds at the end of the 

period for demonstrating compliance is 

required subsequently to obtain 

additional emission reductions to offset 

its excess emissions.280 The agency also 

requests comment on the process for 

invoking requirements for 

implementation of corrective measures 

in response to a state plan performance 

deficiency. 

The EPA further requests comment on 

whether the agency should promulgate 

a mechanism under CAA section 111(d) 

similar to the SIP call mechanism in 

CAA section 110. Under this approach, 

after the agency makes a finding of the 

plan’s failure to achieve the state goal 

during a performance period, the EPA 

would require the state to cure the 

deficiency with a new plan within a 

specified period of time (e.g., 18 

months). If the state still lacked an 

approved plan by the end of that time 

period, the EPA would have the 

authority to promulgate a federal plan 

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

f. Out-Year Requirements: Maintaining 

or Improving the Level of Emission 

Performance Required by the Final Goal 

The agency is determining state goals 

for affected EGU emission performance 

based on application of the BSER during 

specified time periods. This raises the 

question of whether affected EGU 

emission performance should only be 

maintained—or instead should be 

further improved—once the final goal is 

met in 2030. This involves questions of 

goal-setting as well as questions about 

state planning. In this section, the EPA 

proposes that a state must maintain the 

required level of performance, and 

requests comment on the alternative of 

requiring continued improvement. 

The EPA believes that Congress either 

intended the emission performance 

improvements required under CAA 

section 111(d) to be permanent or, 

through silence, authorized the EPA to 

reasonably require permanence. Other 

CAA section 111(d) emission guidelines 

set emission limits to be met 

permanently. Therefore, the EPA is 

proposing that the level of emission 

performance for affected EGUs 

represented by the final goal should 

continue to be maintained in the years 

after 2030. The EPA is proposing a 

mechanism for implementing this 

objective, and is taking comment on an 

alternative option. 

As noted above, the EPA proposes 

that the state plan must demonstrate 

that plan measures are projected to 

achieve the final emission performance 

level by 2030. In addition, the state plan 

must identify requirements that 

continue to apply after 2030 and are 

likely to maintain affected EGU 

emission performance meeting the final 

goal; however, quantitative projections 

of emission performance beyond 2030 

would not be required under the 

proposed option. Instead, the EPA 

proposes that the state plan would be 

considered to provide for maintenance 

of emission performance consistent with 

the final goal if the plan measures used 

to demonstrate projected achievement of 

the final goal by 2030 will continue in 

force and not sunset.281 After 

implementation, the state would be 

required to compare actual plan 

performance against the final goal on a 

rolling three-year average basis starting 

in 2030, and to implement corrective 

measures if necessary. 

The EPA also requests comment on an 

alternative approach to a state’s preimplementation demonstration that the 

final-goal level of performance will be 

maintained after 2030. Under this 

alternative, the state plan would be 

required to include projections 

demonstrating that emission 

performance would continue to meet 

the final goal for up to 10 years beyond 

2030. This approach could be 

implemented through a second round of 

state plan analysis and submittals in 

2025 to make the demonstration and 

strengthen or add measures if necessary. 

The EPA generally requests comment on 

appropriate requirements to maintain 

the emission performance of affected 

EGUs in years after 2030. 

The EPA also requests comment on 

whether we should establish BSERbased state emission performance goals 

for affected EGUs that extend further 

into the future (e.g., beyond the 

proposed planning period), and if so, 

what those levels of improved 

performance should be. Under this 

alternative, the EPA would apply its 

goal-setting methodology based on 

application of the BSER in 2030 and 

beyond to a specified time period and 

final date. The agency requests 

comment on the appropriate time 

period(s) and final year for the EPA’s 

calculation of state goals that reflect 

application of the BSER under this 

approach. 

The EPA notes that CAA section 

111(b)(1)(B) calls for the EPA, at least 

every eight years, to review and, if 

appropriate, revise federal standards of 

performance for new sources. This 

requirement provides for regular 

updating of performance standards as 

technical advances provide technologies 

that are cleaner or less costly. The 

agency requests comment on the 

implications of this concept, if any, for 

CAA section 111(d). 

g. State Flexibility To Choose MassBased and Rate-Based Goals After 2029 

The EPA proposes that states have 

flexibility to choose between a rateVerDate Mar<15>2010 22:32 Jun 17, 2014 Jkt 232001 PO 00000 Frm 00080 Fmt 4701 Sfmt 4702 E:\FR\FM\18JNP2.SGM 18JNP2

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282Flexibilities provided to states in meeting this 

general approvability criterion are discussed below 

in Section VIII.C.2., emission performance. 

283Enforceability guidance includes:(1) 

September 23, 1987 memorandum and 

accompanying implementing guidance, ‘‘Review of 

State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,’’ (2) August 5, 

2004 ‘‘Guidance on SIP Credits for Emission 

Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures,’’ and (3) July 2012 

‘‘Roadmap for Incorporating Energy Efficiency/

Renewable Energy Policies and Programs into State 

and Tribal Implementation Plans, Appendix F.’’ 

284This could include, for example, an expansion 

of the scope or an increase in stringency of the 

current measures in the plan, a second set of 

measures that avoid EGU CO2 emissions, or 

emissions limits that apply to affected EGUs. 

based and mass-based performance level 

for each performance period. For 

example, if a state plan used a massbased performance level for the 2020– 

2029 period, the state plan may still use 

a rate-based performance level for final 

goal performance periods, or vice versa. 

A state that adopted a mass-based 

performance level for 2020–2029 would 

have two options for addressing any 

perceived need for emissions flexibility 

in light of anticipated electricity 

demand growth after 2029. The state 

either could adopt a rate-based 

performance level consistent with the 

final goal, or could adopt a mass-based 

performance level based on a translation 

of the rate-based final goal to a massbased goal. 

h. Planning Approach for Alternative 

State Goals 

In Section VII, the EPA requests 

comment on alternative, five-year state 

emission performance goals for affected 

EGUs shown in Table 9. The alternative 

goals represent emission rates 

achievable on average during the 2020– 

2024 period, as well as emission rates to 

be achieved and maintained after 2024. 

These alternative goals are less stringent 

than the proposed goals in Table 8. 

To accompany the alternative goals, 

the EPA requests comment on another 

approach for state plan performance 

periods. This approach would require 

state plans to demonstrate that the 

required interim emission performance 

level will be met on average by affected 

EGUs during the five-year 2020–2024 

interim period, and that the alternative 

final goal be met no later than 2025. 

After plan implementation, actual 

emission performance would be 

compared with the alternative final goal 

on a three-year rolling average basis, 

starting with 2025–2027, in light of 

year-to-year variability in economic and 

other factors, such as weather, that 

influence power system operation and 

affect EGU CO2 emissions. 

In connection with the alternative 

state goals, for the years after 2027, the 

EPA requests comment on the same 

‘‘out-year’’ issues and concepts for 

maintaining or improving emission 

performance over time that are 

described above in Section VIII.B.2.f. 

The EPA requests comment on whether 

a state plan should provide for emission 

performance after 2025 solely through 

post-implementation emission checks 

that do not require a second plan 

submittal, or whether a state should also 

be required to make a second submittal 

prior to 2025 to demonstrate that its 

programs and measures are sufficient to 

maintain performance meeting the final 

goal for at least 10 years. In addition, the 

agency requests comment on the 

appropriate date for any second state 

plan submittal designed to maintain 

emission performance after the 2025 

performance level is achieved. 

C. Criteria for Approving State Plans 

The EPA is proposing to require the 

twelve plan components discussed in 

Section VIII.D of this preamble. We will 

evaluate the sufficiency of each plan 

based on the plan addressing those 

components and on four general criteria 

for a state plan to be approvable. The 

EPA proposes to use the combination of 

these twelve plan components and four 

general criteria to determine whether a 

state’s plan is ‘‘satisfactory’’ under CAA 

section 111(d)(2)(A). First, a state plan 

must contain enforceable measures that 

reduce EGU CO2 emissions. Second, 

these enforceable measures must be 

projected to achieve emission 

performance equivalent to or better than 

the applicable state-specific CO2 goal on 

a timeline equivalent to that in the 

emission guidelines.282 Third, EGU CO2

emission performance under the state 

plan must be quantifiable and verifiable. 

Fourth, the state plan must include a 

process for state reporting of plan 

implementation (at the level of the 

affected entity), CO2 emission 

performance outcomes, and 

implementation of corrective measures, 

if necessary. The EPA requests 

comments on all aspects of these general 

criteria and the twelve specific plan 

components described below. 

The agency also notes that a CAA 

section 111(d) state plan is not a CAA 

section 110 state implementation plan 

(SIP). Although there are similarities in 

the two programs, approvability criteria 

for CAA section 111(d) plans need not 

be identical to approvability criteria for 

SIPs. 

1. Enforceable Measures 

In developing its plan, a state must 

ensure that the plan is enforceable and 

in conformance with the CAA. We are 

seeking comment on the 

appropriateness of existing EPA 

guidance on enforceability in the 

context of state plans under CAA 

section 111(d), considering the types of 

affected entities that might be included 

in a state plan.283 This guidance serves 

as the foundation for the types of 

emission limits that the EPA has found 

can be enforced as a practical matter 

and sets forth the general principle that 

a requirement that is enforceable as a 

practical matter is one that is 

quantifiable, verifiable, straightforward, 

and calculated over as short a term as 

reasonable. 

As discussed in section VIII.F.1, the 

EPA is seeking comment on whether the 

agency should provide guidance on 

enforceability considerations related to 

requirements in a state plan for entities 

other than affected EGUs (and if so, 

which types of entities). Also, as 

discussed in section VIII.F.4, the EPA 

intends to develop guidance for 

evaluation, monitoring, and verification 

(EM&V) of renewable energy and 

demand-side energy efficiency programs 

and measures incorporated in state 

plans. 

A state plan must include enforceable 

CO2 emission limits (either rate-based or 

mass-based) that apply to affected EGUs. 

As noted above, the EPA is proposing 

that a state plan may take a portfolio 

approach, which would include 

enforceable CO2 emission limits that 

apply to affected EGUs as well as other 

enforceable measures, such as RE and 

demand-side EE measures, that avoid 

EGU CO2 emissions and are 

implemented by the state or by another 

entity assigned responsibility by the 

state. As noted above, we are proposing 

that state plans are not required to 

impose emission limits on affected 

EGUs that in themselves fully achieve 

the emission performance level. 

However, we are seeking comment on 

whether, for state plans where emission 

limits applicable to affected EGUs alone 

would not assure full achievement of 

the required level of emission 

performance, the state plan must 

include additional measures that would 

apply if any of the other portfolio of 

measures in the plan are not fully 

implemented, or if they are, but the plan 

fails to achieve the required level of 

emission performance.284

The EPA recognizes that a portfolio 

approach may result in enforceable state 

plan obligations accruing to a diverse 

range of affected entities beyond 

affected EGUs, and that there may be 

challenges to practically enforcing 

against some such entities in the event 

of noncompliance. We request comment 


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285Considerations for quantification, monitoring, 

and verification of RE and demand-side EE 

measures are addressed in Section VII.F.4 of this 

preamble and in the State Plan Considerations TSD. 

on all aspects associated with 

enforceability of a state plan and how to 

ensure compliance. We are also seeking 

comment on enforceability 

considerations under different state plan 

approaches, which is addressed below 

in VIII.F.1. 

2. Emission Performance 

The second criterion for approvability 

is that the projected CO2 emission 

performance by affected EGUs (taking 

into account the impacts of plan 

measures that are associated with 

reducing utilization from affected EGUs) 

must be equivalent to, or better than, the 

required CO2 emission performance 

level in the state plan. State plans that 

are projected to achieve an average CO2

emission rate (expressed in lb CO2/

MWh) or tonnage CO2 emission 

outcome by all affected EGUs equal to, 

or lower than, the required level of CO2

emission performance in the plan would 

meet this approvability criterion. 

We are proposing that states may 

demonstrate such emission performance 

by affected EGUs either on an 

individual state basis or jointly on a 

multi-state basis. 

All of the emission reduction 

measures included in the agency’s 

determination of the BSER reduce CO2

emissions from affected EGUs. As a 

result, the EPA is not proposing that 

out-of-sector GHG offsets could be 

applied to demonstrate CO2 emission 

performance by affected EGUs in a state 

plan. 

However, emission limits for affected 

EGUs that are included in state plans 

could still include provisions that 

provide the ability to use GHG offsets 

for compliance with the emission limits, 

provided those emission limits would 

achieve the required level of emission 

performance for affected EGUs. We note 

that inclusion of such provisions would 

create a degree of uncertainty about the 

level of emission performance that 

would be achieved by affected EGUs 

when complying with the emission 

limit (as potentially would other 

flexibility mechanisms included in an 

emission limit). As a result, such 

emission limits would not be 

considered ‘‘self-correcting’’ as 

discussed above at Section VIII.B.2.d. 

All existing state emission budget 

trading programs addressing GHG 

emissions include out-of-sector, projectbased emission offsets, which may be 

used to cover a portion of the 

compliance obligation of affected 

sources. Other states may want to take 

a similar approach, for example, to 

incentivize GHG emission reductions 

from land use and agricultural waste 

management. How to address GHG 

offsets included in EGU emission limits 

when projecting emission performance 

under a state plan is addressed in the 

Projecting EGU CO2 Emission 

Performance in State Plans TSD. 

The ISO/RTO Council, an 

organization of electric grid operators, 

has suggested that ISOs and RTOs could 

play a facilitative role in developing and 

implementing region-wide, multi-state 

plans, or coordinated individual state 

plans. Existing ISOs and RTOs could 

provide a structure for achieving 

efficiencies by coordinating the state 

plan approaches applied throughout a 

grid region. Just as the ISO/RTO regions 

today share the benefits and costs of 

efficient EGU dispatch across state 

boundaries, there are significant 

efficiencies that could be captured by 

coordinating individual state plans or 

implementing multi-state plans within a 

grid region. Under one variant of this 

approach, states would implement a 

multi-state plan and jointly demonstrate 

CO2 emission performance by affected 

EGUs across the entire ISO/RTO 

footprint. States with borders that cross 

the boundary of one or more ISO or RTO 

footprints would need to include 

multiple plan components that address 

affected EGUs in each respective ISO or 

RTO. The EPA is seeking comment on 

this idea. States that are outside the 

footprint of an ISO or RTO may benefit 

from consulting with other relevant 

planning authorities when preparing 

state plans. We are also requesting 

comment on this idea. 

3. Quantifiable and Verifiable Emission 

Performance 

The third criterion for approvability is 

that a state plan specify how the effects 

of each state plan measure will be 

quantified and verified. The EPA 

proposes that all plans must specify 

how CO2 emissions from affected EGUs 

are monitored and reported. The EPA is 

proposing that both mass-based and 

rate-based plans must include CO2

emission monitoring, reporting, and 

recordkeeping requirements for affected 

EGUs, as specified in the emission 

guidelines. A rate-based plan must also 

include monitoring, reporting, and 

recordkeeping requirements for useful 

energy output from affected EGUs 

(electricity and useful thermal output), 

as specified in the emission guidelines. 

With one exception, these proposed 

requirements are consistent with those 

in the proposed EGU Carbon Pollution 

Standards for New Power Plants. See 79 

FR 1430–1519 (January 8, 2014). The 

exception is that we are proposing that 

useful energy output be measured in 

terms of net output rather than gross 

output, as discussed below. 

For state plans that include other 

measures that avoid EGU CO2

emissions, such as RE and demand-side 

EE measures, the state will also need to 

include quantification, monitoring, and 

verification provisions in its plan for 

these measures, which may vary 

depending on the types of requirements 

included in the specific plan, as 

specified in the emission guidelines. 

This may include, for example, 

quantification, monitoring, and 

verification of RE generation and 

demand-side EE energy savings under a 

rate-based approach.285

4. Reporting and Corrective Actions 

The fourth criterion for approval is 

that a state plan must (i) specify a 

process for annual reporting to the EPA 

of overall plan performance and 

implementation (including compliance 

of affected entities with applicable 

emission standards) during the plan 

performance periods, and (ii) include a 

process and schedule for implementing 

corrective measures if reporting shows 

that the plan is not achieving the 

projected level of emission performance. 

We solicit comment on whether the 

latter process should include the 

adoption of new plan measures and 

subsequent resubmission of the plan to 

the EPA for review and approval, or 

whether the process should specify the 

implementation of measures that are 

already included in the approved plan 

in the event that the projected level of 

performance is not being achieved. We 

also solicit comment on the point at 

which such a process and schedule 

would be triggered, such as at the end 

of a multi-year plan performance period 

if emission performance is not met, or 

at specified interim stages within a 

multi-year plan performance period. For 

plans with self-correcting mechanisms, 

the agency is not proposing that 

requirements for corrective measures be 

included in the plan. All of these 

considerations are addressed in more 

detail above in Section VIII.B.2. 

The agency is also proposing that a 

state plan specify appropriate periodic 

reporting requirements for each affected 

entity in a state plan that will be 

reported at least annually, 

electronically, and disclosed on a state 

database accessible by the public and 

the EPA. The EPA is requesting 

comment on the appropriate scope of 

these reporting requirements and 

whether the reports should also be 

directly submitted by the affected 


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entities to the EPA, as well as to the 

state. 

D. State Plan Components 

The EPA is proposing that an 

approvable plan must meet the 

approvability criteria described above 

and include the twelve state plan 

components summarized below, 

consistent with additional specific 

requirements explained elsewhere in 

this notice. Plans must comply with the 

EPA framework regulations at 40 CFR 

60.23–60.29, except as specified 

otherwise by these emission guidelines. 

These requirements apply both to 

individual state plans and multi-state 

plans. 

For states wishing to participate in a 

multi-state plan, the EPA is proposing 

that only one multi-state plan would be 

submitted on behalf of all participating 

states. The joint submittal would be 

signed by authorized officials for each of 

the states participating in the multi-state 

plan and would have the same legal 

effect as an individual submittal for 

each participating state. The joint 

submittal would adequately address 

plan components that apply jointly for 

all participating states and for each 

individual state in the multi-state plan, 

including necessary state legal authority 

to implement the plan, such as state 

regulations and statutes. Because the 

multi-state plan functions as a single 

plan, each of the required plan 

components described below (e.g., plan 

performance levels, program 

implementation milestones, emission 

performance checks, and reporting) 

would be designed and implemented by 

the participating states on a multi-state 

basis. 

We are also seeking comment on two 

additional options for multi-state plan 

submittals. These options could 

potentially provide states with 

flexibility in addressing contingencies 

where one or more states submit plan 

components that are not approvable. In 

such instances, these options would 

simplify EPA approval of remaining 

common or individual portions of a 

multi-state plan. These options might 

also address contingencies during plan 

development where a state fails to 

finalize its participation in a multi-state 

plan, with minimal disruption to the 

submittals of the remaining 

participating states. 

First, the EPA is seeking comment on 

whether states participating in a multistate plan should also be given the 

option of providing a single submittal— 

signed by authorized officials from each 

participating state — that addresses 

common plan elements. Individual 

participating states would also be 

required to provide individual 

submittals that provide state-specific 

elements of the multi-state plan. Both 

the common multi-state submittal and 

each individual participating state 

submittal would be required to address 

all twelve plan components described 

below (even if only through cross 

reference to either the common 

submittal or individual submittals, as 

appropriate). Under this approach, the 

combined common submittal and each 

of the individual participating state 

submittals would constitute the multistate plan submitted for EPA review. 

Second, the EPA is seeking comment 

on an approach where all states 

participating in a multi-state plan 

separately make individual submittals 

that address all elements of the multistate plan. These submittals would need 

to be materially consistent for all 

common plan elements that apply to all 

participating states, and would also 

address individual state-specific aspects 

of the multi-state plan. Each individual 

state plan submittal would need to 

address all twelve plan components. 

The EPA proposes that each plan 

must have the following twelve 

components, except as indicated 

otherwise for self-correcting plans: 

1. Identification of Affected Entities 

(Affected EGUs and Other Responsible 

Parties) 

A state plan must list the individual 

affected EGUs in the state that are 

subject to the plan and provide an 

inventory of CO2 emissions from those 

units (for the most recent calendar year 

prior to plan submission for which data 

are available), and identify any other 

affected entities in a state plan with 

responsibilities for implementation and 

enforceable obligations under the plan. 

2. Description of Plan Approach and 

Geographic Scope 

The state plan must describe its 

approach and geographic scope, 

including whether the state will achieve 

its required level of CO2 emission 

performance on an individual state basis 

or jointly through a multi-state 

demonstration. 

3. Identification of State Emission 

Performance Level 

The state plan must identify the 

state’s proposed emission performance 

level, which will either be the ratebased CO2 emission goal identified for 

the state in the emission guidelines or 

a translation of the rate-based goal to a 

mass-based goal. 

A state plan must identify the ratebased or mass-based level of emission 

performance that must be met through 

the plan, (expressed in numeric values, 

including the units of measurement for 

the level of performance, such as 

pounds of CO2 per net MWh of useful 

energy output or tons of CO2). As noted, 

in the emission guidelines, the EPA will 

establish the state goal in the form of a 

CO2 emission rate, and the state may, for 

its emission performance level, either 

adopt that rate or translate it into a 

mass-based goal. If the plan adopts a 

mass-based goal, the plan must include 

a description of the analytic process, 

tools, methods, and assumptions used to 

translate from the rate-based goal to the 

mass-based goal. 

The EPA is proposing that multiple 

states could jointly demonstrate 

emission performance by affected EGUs. 

For these multi-state approaches, states 

would demonstrate emission 

performance by affected EGUs in 

aggregate with partner states. For states 

participating in a multi-state approach, 

the individual state performance goals 

in the emission guidelines would be 

replaced with an equivalent multi-state 

performance goal. For example, states 

taking a rate-based approach would 

demonstrate that all affected EGUs 

subject to the multi-state plan achieve a 

weighted average CO2 emission rate that 

is consistent, in aggregate, with an 

aggregation of the state-specific ratebased CO2 emission performance goals 

established in the emission guidelines 

that apply to each of the participating 

states. If states were taking a mass-based 

approach, participating states would 

demonstrate that all affected EGUs 

subject to the multi-state plan emit a 

total tonnage of CO2 emissions 

consistent with a translated multi-state 

mass-based goal. This multi-state massbased goal would be based on 

translation of an aggregation of the statespecific rate-based CO2 emission 

performance goals established in the 

emission guidelines that apply to each 

of the participating states. 

The EPA is seeking comment on two 

options for calculating a weighted 

average, rate-based CO2 emission 

performance goal for multiple states. 

Under the first option, the weighted 

average emission rate goal for a group of 

participating states is computed using 

each state’s emission rate goal from the 

emission guidelines and the quantity of 

electricity generation by affected EGUs 

in each of those states during the 2012 

base year that the EPA used in 

calculating the state-specific goals. 

Different levels would be computed for 

the interim and final goals. This 

approach is consistent with the method 

used to calculate the state-specific, ratebased emission performance goals. 

However, it does not address the fact 


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that the weighted average emission rate 

performance goal for multiple states 

may be influenced significantly by the 

weighting of electricity generation from 

affected EGUs in different states. This 

mix of generation among affected EGUs 

in different states could differ 

significantly during the plan 

performance periods from that during 

the 2012 base year. 

Under the second option, the 

weighted average emission rate goal for 

a group of participating states is 

computed using each state-specific 

emission rate goal and the quantity of 

projected electricity generation by 

affected EGUs in each state. The 

calculation would be performed for the 

2020 through 2029 period to produce a 

multi-state interim goal, and for 2030 to 

produce a multi-state final goal. This 

projection of electricity generation by 

affected EGUs would be for a reference 

case that does not include application of 

either the state-specific rate-based 

emission performance goals for the 

participating states or the requirements, 

programs, and measures included in the 

multi-state plan. This approach 

addresses the fact that the mix of 

generation among affected EGUs in 

different states could differ significantly 

during the plan performance periods 

from that during the 2012 base year. As 

a result, it would base the weighted 

average goal in part on the anticipated 

business-as-usual mix of generation by 

affected EGUs across the multiple states 

during the plan performance period. 

However, this approach could also 

significantly alter the weighted average 

performance goal based on projected 

retirements of affected EGUs in one or 

more states. 

Under both options, the rate-based 

multi-state goal could be translated to a 

mass-based goal. These options, and the 

procedure for translation to a massbased goal, are discussed in more detail 

in the Projecting EGU CO2 Emission 

Performance in State Plans TSD. 

We are requesting comment on 

whether, to assist states that seek to 

translate the rate-based goal into a massbased goal, the EPA should provide a 

presumptive translation of rate-based 

goals to mass-based goals for all states, 

for those who request it, and/or for 

multi-state regions. As another 

alternative, the EPA could provide 

guidance for states to use in translating 

a rate-based goal to a mass-based goal 

for individual states and for multi-state 

regions. This could include information 

about acceptable analytical methods and 

tools, as well as default input 

assumptions for key parameters that 

will likely influence projections, such as 

electricity load forecasts and projected 

fossil fuel prices. Under this approach, 

the EPA might also provide a 

coordinating function in addressing the 

assumptions applied by multiple states 

within a grid region, acknowledging that 

assumptions about state programs across 

a broader grid region that are included 

in an analysis scenario may influence 

projections of CO2 emissions by affected 

EGUs in one or more particular states in 

the grid region. The agency is seeking 

comment on the process for establishing 

mass-based emission goals, including 

the options summarized above for the 

EPA’s and states’ roles in the translation 

process. 

Technical considerations involved in 

translating from rate-based goals to 

mass-based goals are discussed in detail 

in the Projecting EGU CO2 Emission 

Performance in State Plans TSD. The 

TSD includes a discussion of possible 

acceptable analytical methods, tools, 

and key assumption inputs that will 

influence projections. The agency 

invites comment on these technical 

considerations. 

4. Demonstration That the Plan Is 

Projected To Achieve the State’s 

Emission Performance Level 

A state plan must demonstrate that 

the actions taken pursuant to the plan 

are, when taken together, projected to 

achieve emission performance by 

affected entities that, on average, will 

meet the state’s required emission 

performance level for affected EGUs 

during the initial 2020–2029 plan 

performance period, and will meet the 

required final emission performance 

level in 2030. This demonstration will 

include a detailed description of the 

analytic process, tools, and assumptions 

used to project future CO2 emission 

performance by affected EGUs under the 

plan and the results of the analysis. 

Considerations related to projecting the 

emission performance of affected EGUs 

under a state plan are discussed in 

section VIII.F.7 and in the Projecting 

EGU CO2 Emission Performance in State 

Plans TSD. 

5. Milestones 

As described in greater detail in 

Section VIII.B.2.d., state plans must 

include periodic programmatic 

milestones to show progress in program 

implementation if the plan is not selfcorrecting (i.e., does not inherently 

require both interim progress and the 

full level of required emission 

performance in a manner that is 

federally enforceable against affected 

EGUs). These programmatic milestones 

with specific dates for achievement 

should be appropriate to the programs 

and measures included in the plan. 

In addition, the state plan 

demonstration will indicate the plan’s 

intended trajectory of emission 

performance improvement. As 

described in Section VIII.B.2.d., each 

year during the interim performance 

period, beginning in 2022 the state must 

compare the collective emission 

performance achieved by affected 

entities in the state during the previous 

two-year period with performance 

projected in the state plan. If actual 

emission performance is not within 10 

percent of original projections, the state 

must submit a report by the July 1 

following the end of the two-year period 

(submitted as part of the state’s annual 

report on plan performance described 

below in section VIII.D.10) to explain 

reasons for the deviation and specify the 

corrective actions that will be taken to 

ensure that the required level of 

emission performance in the plan will 

be met. 

6. Corrective Measures 

For a plan that does not include selfcorrecting mechanisms, the plan must 

also specify corrective measures that 

will be implemented if the state’s 

progress in achieving its level of 

performance for affected EGUs falls 

short of what is projected under the 

plan, as well as a process and schedule 

for implementing any such measures. 

The agency requests comment on the 

amount of emission rate improvement 

or emission reduction that the corrective 

measures included in the plan must be 

designed to achieve (e.g., measures 

sufficient to address a 10 percent 

performance deficiency). The agency 

also seeks comment on whether the 

emission guidelines should establish a 

deadline for implementation of 

corrective measures (e.g., two years from 

the July 1 deadline described above for 

reporting the deficiency as part of the 

state’s annual report on plan 

performance). Corrective measure 

provisions are discussed in more detail 

above in section VIII.B.2.d and in 

section VIII.B.2.f. 

7. Identification of Emission Standards 

and Any Other Measures 

A state plan must identify the affected 

entities to which each emission 

standard applies (e.g., individual 

affected EGUs, groups of affected EGUs, 

all the state’s affected EGUs in 

aggregate, other affected entities that are 

not EGUs), as well as any implementing 

and enforcing measures for such 

standards, and describe each emission 

standard and the process for 

demonstrating compliance with it 

pursuant to state regulations or another 

legal instrument, including the schedule 


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286EPA guidance on enforceability includes: (1) 

September 23, 1987 memorandum and 

accompanying implementing guidance, ‘‘Review of 

State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,’’ (2) August 5, 

2004 ‘‘Guidance on SIP Credits for Emission 

Reductions from Electric-Sector Energy Efficiency 

and Renewable Energy Measures,’’ and (3) July 2012 

‘‘Roadmap for Incorporating Energy Efficiency/

Renewable Energy Policies and Programs into State 

and Tribal Implementation Plans, Appendix F.’’ 

for compliance for each affected entity. 

In its proposed Carbon Pollution 

Standards (79 FR 1430–1519, January 8, 

2014), the EPA proposed that the 

appropriate averaging time for an 

emission standard for new EGUs be no 

longer than 12 months. Similarly, the 

EPA proposes here that an appropriate 

averaging time for any rate-based 

emission standard for affected EGUs 

and/or other affected entities subject to 

a state plan is no longer than 12 months 

within a plan performance period and 

no longer than three years for a massbased standard. We also solicit 

comment on longer and shorter 

averaging times for emission standards 

included in a state plan. 

8. Demonstration That Each Emission 

Standard Is Quantifiable, NonDuplicative, Permanent, Verifiable, and 

Enforceable 

In developing its CAA section 111(d) 

plan, a state must ensure that its plan is 

enforceable and in conformance with 

the CAA. As discussed in section 

VIII.C.1, we are seeking comment on the 

appropriateness of existing EPA 

guidance on enforceability in the 

context of state plans under CAA 

section 111(d), considering the types of 

affected entities that might be included 

in a state plan.286 This guidance serves 

as the foundation for the types of 

monitoring, reporting, and limits that 

the EPA has found can be, as a practical 

matter, enforced, and set forth the 

general principle that a requirement that 

is enforceable as a practical matter is 

one that is quantifiable, verifiable, 

straightforward and is calculated over as 

short a term as reasonable. 

As discussed in section VIII.F.1, the 

EPA is seeking comment on whether the 

agency should provide guidance on 

enforceability considerations related to 

requirements in a state plan for entities 

other than affected EGUs (and if so, 

which types of entities). Also, as 

discussed in section VIII.F.4, the EPA 

intends to develop guidance for 

evaluation, monitoring, and verification 

(EM&V) of renewable energy and 

demand-side energy efficiency programs 

and measures incorporated in state 

plans. 

For each emission standard, a plan 

must describe how it is quantifiable, 

non-duplicative, permanent, verifiable, 

and enforceable with respect to an 

affected entity. An emission standard is 

quantifiable if it can be reliably 

measured, using technically sound 

methods, in a manner that can be 

replicated. These issues are discussed 

further in Section VIII.F.4 and in the 

State Plan Considerations TSD. 

An emission standard is nonduplicative with respect to an affected 

entity if it is not already incorporated in 

another state plan, except in instances 

where incorporated in another state as 

part of a multi-state plan. An example 

of a duplicative emission standard 

would occur where recognition of 

avoided CO2 emissions from, for 

example, a wind farm, could be applied 

in more than one state’s CAA section 

111(d) plan, except in the case of a 

multi-state plan where recognition is 

assigned among states or emission 

performance is demonstrated jointly for 

all affected EGUs subject to the multistate plan. This does not mean that 

measures in an emission standard 

cannot also be used for other purposes. 

For example, if a state wished to take 

credit for CO2 emissions avoided due to 

electric generation from a new wind 

farm, those avoided emissions could be 

considered non-duplicative and 

included for purposes of CAA section 

111(d), even if electric generation from 

that wind farm was also being used to 

generate renewable energy certificates 

(RECs) to comply with the state’s RPS 

requirements. It also does not mean that 

a single affected entity could not be 

subject to similar emission standards in 

different state plans. For example, an 

affected entity might be an electric 

distribution utility that has a service 

territory that crosses state lines. This 

entity might be subject to a separate 

state demand-side EE requirement for 

electricity supplied in each of the states 

where it serves electricity customers. In 

this instance, the same company could 

be an affected entity subject to a 

different state demand-side EE 

requirement in each state plan, without 

these emission standards in each plan 

being considered duplicative. The EPA 

solicits comment on whether an 

emission reduction becomes duplicative 

(and therefore cannot be used for 

demonstrating performance in a plan) if 

it is used as part of another state’s 

demonstration of emission performance 

under its CAA section 111(d) plan. 

An emission standard is permanent if 

the standard must be met for each 

applicable compliance year or period, or 

replaced by another emission standard 

in a plan revision, or the state 

demonstrates in a plan revision that the 

emission standard is no longer 

necessary for the state to meet its 

required emission performance level for 

affected EGUs. 

An emission standard is verifiable if 

adequate monitoring, recordkeeping and 

reporting requirements are in place to 

enable the state and the Administrator 

to independently evaluate, measure, and 

verify compliance with it. This is 

discussed further in Section VIII.F.4 and 

in the State Plan Considerations TSD. 

An emission standard is enforceable if: 

(1) It represents a technically accurate 

limitation or requirement and the time 

period for the limitation or requirement 

is specified, (2) compliance 

requirements are clearly defined, (3) the 

affected entities responsible for 

compliance and liable for violations can 

be identified, (4) each compliance 

activity or measure is practically 

enforceable in accordance with EPA 

guidance on practical enforceability (as 

discussed in Section VIII.F.1 of this 

preamble), and the Administrator and 

the state maintain the ability to enforce 

against violations and secure 

appropriate corrective actions pursuant 

to CAA sections 113(a)–(h). 

9. Identification of Monitoring, 

Reporting, and Recordkeeping 

Requirements 

The state plan must describe the CO2

emission monitoring, reporting, and 

recordkeeping requirements for affected 

EGUs, including requirements for 

monitoring and reporting of useful 

energy output if a state plan is taking a 

rate-based approach. The EPA is 

proposing that each plan include 

monitoring, reporting, and 

recordkeeping requirements for CO2

emissions and useful energy output (if 

applicable) that are materially 

consistent with the requirements 

specified in the emission guidelines. 

State plans with a rate-based form of the 

emission performance level must 

require affected EGUs to report hourly 

net energy output (including net MWh 

generation, and where applicable, useful 

thermal output) to the EPA on an annual 

basis. 

Most affected EGUs already monitor 

CO2 emissions under 40 CFR Part 75 

and report the data using the EPA’s 

Emission Collection and Monitoring 

Plan System (ECMPS), which would 

generally satisfy CO2 emission reporting 

requirements under the proposed 

guidelines. However, we are seeking 

comment on two possible adjustments 

to the Part 75 Relative Accuracy Test 

Audit (RATA) requirements for steam 

EGU stack gas flow monitors that can 

affect reported CO2 emissions. The first 

possible adjustment would be to require 

use of the most accurate RATA 


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287 70 FR 1429–1519; January 8, 2014. 

reference method for specific stack 

configurations, while the second 

possible adjustment would be to require 

a computation adjustment when an EGU 

changes RATA reference methods. The 

rationale for these possible adjustments 

is described further in the Part 75 

Monitoring and Reporting 

Considerations TSD available in the 

docket. 

We are also proposing monitoring and 

reporting protocols for net energy 

output under 40 CFR Part 75 that would 

allow the ECMPS to be used for 

purposes of meeting the net energy 

output reporting requirement. Affected 

facilities with multiple generators (e.g., 

combined cycle facilities) would be 

required to report the electric output 

from all generators. The proposed 

protocols include a default 

apportionment procedure for multi-EGU 

facilities under which the net generation 

of each EGU at the facility would be 

determined as the net generation of the 

facility multiplied by the ratio of the 

EGU’s gross generation to the sum of the 

gross generation for all EGUs at the 

facility. (In the case of EGUs producing 

both electric energy output and useful 

thermal output, the apportionment 

procedure would include a thermal-toelectric energy conversion calculation as 

provided in the proposed EGU GHG 

NSPS regulations.287) We solicit 

comment on whether EGUs producing 

both electric energy output and useful 

thermal output should be required to 

report both electric and useful thermal 

output. In addition, the proposed 

protocols would allow facilities to use 

alternative apportionment procedures 

with EPA approval. We invite comment 

on the proposal for reporting of net 

rather than gross energy output and on 

the proposed protocols. Specifically, we 

are seeking comment on: Any existing 

protocols for reporting net output 

(FERC, NERC, etc.); electricity meter 

specifications; electricity meter quality 

assurance testing and reporting 

procedures; apportionment procedures 

for parasitic load at multi-unit facilities; 

treatment of externally provided 

electricity; and monitoring and quality 

assurance testing and reporting 

procedures for non-electric energy 

output at CHP units. (Options regarding 

these topics are discussed in the TSD 

mentioned above.) Also, consistent with 

the requests for comment in the 

proposed CAA section 111(b) GHG 

NSPS regulations for modified and 

reconstructed sources, we invite 

comment here on a range of two-thirds 

to 100 percent credit for useful thermal 

output in the final rule, or other 

alternatives to better align incentives 

with avoided emissions. 

A state plan that contains other 

emission standards, in addition to 

emission limits applicable to affected 

EGUs, must include additional reporting 

and recordkeeping requirements related 

to these other measures. These reporting 

and recordkeeping requirements will 

consist of the data necessary for each 

affected entity to demonstrate 

compliance with its obligations. This 

could include, for example, reporting of 

MWh electricity savings achieved by an 

electric distribution utility under an 

end-use energy efficiency resource 

standard and utility compliance with 

requirements of the standard. These 

requirements might also include 

comparable reporting by an electric 

distribution utility of renewable energy 

certificates (RECs) held, or renewable 

energy purchased or generated, under a 

renewable energy portfolio standard, 

and compliance with the standard. This 

is discussed further in Section VIII.F.5 

and the State Plan Considerations TSD. 

The EPA is proposing that state plans 

must include a record retention 

requirement of ten years, and we request 

comment on this proposed timeframe. 

10. Description of State Reporting 

A state plan must provide that the 

state will submit reports to the EPA 

detailing plan implementation and 

progress, including the actions taken by 

the state, affected EGUs, and any other 

affected entities under the plan; the 

status of compliance by affected EGUs 

and any other affected entities with 

their obligations under the plan; current 

aggregate and individual CO2 emission 

performance by affected EGUs during 

the reporting year and prior reporting 

years; and any additional measures 

applied under the plan during the 

reporting period. The state plan must 

describe the process, timing, and 

content for these reports. The EPA is 

proposing that an annual report is due 

no later than the July 1 following the 

end of the reporting year. 

While some of the proposed reporting 

requirements such as reporting of EGU 

emissions (which can be done through 

existing reporting mechanisms) would 

not place additional burdens on states, 

others may require assembling 

information that is being reported under 

state programs into a single report. For 

example, in the case of a rate-based state 

plan that calls for adjusting the actual 

emission rate of the state’s affected 

EGUs based on emissions avoided 

through renewable energy or end-use 

energy efficiency programs, the 

requirement for comparing actual plan 

performance against projected plan 

performance requires the state to 

incorporate information on results 

achieved by those programs each year. 

This emission performance comparison 

serves as the basis for showing either 

that a state plan is on track or that 

corrective measures are needed. 

Another reporting element is a list of 

facilities and their compliance status. 

The EPA is requesting comment on the 

appropriate frequency of reporting of 

the different proposed reporting 

elements, considering both the goals of 

minimizing unnecessary burdens on 

states and ensuring program 

effectiveness. In particular, the agency 

requests comment on whether full 

reports containing all of the report 

elements should only be required every 

two years. 

In addition, the EPA is soliciting 

comment on whether these reports 

should be submitted electronically, to 

streamline transmission. 

11. Certification of State Plan Hearing 

A state plan must provide 

certification that a hearing on the state 

plan was held, a list of witnesses and 

their organizational affiliations, if any, 

appearing at the hearing, and a brief 

written summary of each presentation or 

written submission pursuant to the 

requirements of the EPA framework 

regulations at 40 CFR 60.23–60.29. 

12. Supporting Material 

The state must provide supporting 

material and technical documentation 

related to applicable components of the 

plan. In its plan, a state must adequately 

demonstrate that it has the legal 

authority for each implementation and 

enforcement component that it has 

included in its plan as part of a federally 

enforceable emission standard. A state 

can make such a demonstration by 

providing supporting material related to 

the state’s legal authority used to 

implement and enforce each component 

of the plan, such as statutes, regulations, 

public utility commission orders, and 

any other applicable legal instruments. 

A state plan must also provide 

analytical materials used in translating 

a rate-based goal to a mass-based goal (if 

a translation is included), analytical 

materials used in projecting emission 

performance that will be achieved 

through the plan, relevant 

implementation materials, and any 

additional technical requirements and 

guidance the state proposes to use to 

implement elements of the plan. 


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288 40 CFR 60.23(a)(1). 

E. Process for State Plan Submittal and 

Review 

1. Overview 

Under the framework regulations, 

state plans would be due nine months 

after finalization of the emission 

guidelines. 40 CFR 60.23(a)(1). The 

President in his June 25, 2013 

Memorandum specified that states 

should submit plans by June 30, 2016, 

which would provide states thirteen 

months. During the outreach process, 

many states expressed concern that this 

was not sufficient time to prepare and 

submit a state plan to the EPA. States 

commented that additional time was 

needed to accommodate, among other 

things, state legislative and rulemaking 

schedules, coordination among states 

involved in multi-state plans, 

coordination with third parties, and the 

complex technical work needed to 

develop a state plan. The EPA 

recognizes that state administrative 

procedures can be lengthy, some states 

may need new legislative authority, and 

states planning to join in a multi-state 

plan will likely need more than thirteen 

months to get necessary elements in 

place. Balanced against that concern, 

however, is the urgency of addressing 

carbon emissions and the fact that there 

are certain steps we believe states can 

take within thirteen months to set 

themselves on a clear path to adoption 

of a complete plan. Therefore, the EPA 

is proposing a plan submittal process 

with a submittal date of June 30, 2016 

(thirteen months after the expected 

finalization date of the emission 

guidelines), which provides additional 

time to submit a complete plan to the 

EPA after June 30, 2016, when justified. 

Part of that justification would include 

the state’s demonstration of having 

taken meaningful steps during the first 

thirteen months toward submitting a 

complete plan. This approach involves 

the option that we refer to as an initial 

submittal, followed by submittal of a 

complete state plan no later than either 

June 30, 2017 for single-state plans or 

June 30, 2018 for multi-state plans. 

In addition, for states wishing to 

participate in a multi-state plan, the 

EPA is proposing that only one multistate plan would be submitted on behalf 

of all participating states, provided it is 

signed by authorized officials for each of 

the states participating in the multi-state 

plan and contains the necessary 

regulations, laws, etc. for each state in 

the multi-state plan. In this instance, the 

joint submittal would have the same 

legal effect as an individual submittal 

for each participating state. 

2. State Plan Submittal and Timing 

The EPA framework regulations (40 

CFR 60.23) require that state plans be 

submitted to the EPA within nine 

months of promulgation of the emission 

guidelines, unless the EPA specifies 

otherwise.288 In view of the potential 

that these plans may require states to 

develop new regulatory or statutory 

authority, we are proposing that each 

state must submit a plan to the EPA by 

June 30, 2016, which is more than one 

year after the expected finalization date 

of the emission guidelines. The state 

may submit a complete plan, or if 

justified, an initial plan that documents 

the state’s progress in preparing a 

complete plan. To qualify for an 

extension of the June 30, 2016 deadline 

for submitting a complete plan, the state 

must submit an initial plan that 

demonstrates the state is on track to 

develop a complete plan and that 

includes meaningful steps that clearly 

commit the state to complete an 

approvable plan. 

The EPA proposes that approvable 

justifications for seeking an extension 

beyond 2016 for submitting a complete 

plan include: A state’s required 

schedule for legislative approval and 

administrative rulemaking, the need for 

multi-state coordination in the 

development of an individual state plan, 

or the process and coordination 

necessary to develop a multi-state plan. 

The EPA is requesting comment on 

other circumstances for which an 

extension of time would be appropriate. 

We are also seeking comment on 

whether some justifications for 

extension should not be permissible. 

If a state submits an initial state plan 

by June 30, 2016, and it meets the 

minimum requirements for an initial 

state plan, as specified in the plan 

guidelines, then the deadline extension 

for submitting a complete plan that the 

state requested will be deemed granted. 

If the EPA determines that the initial 

plan does not meet the guidelines, the 

EPA will notify the state by letter, 

within 60 days, that the agency cannot 

approve the state’s initial plan as 

submitted. The EPA believes this 

approach is authorized by, and 

consistent with, section 60.27(a) of the 

implementing regulations. 

If the EPA approves a two-year 

extension to June 30, 2018, for a state 

developing a multi-state plan, the state 

would be required to provide one 

update, on June 30, 2017, on its progress 

toward milestones and schedules in the 

initial plan for developing and 

submitting a complete plan. We are 

requesting comment on this approach 

and the timing and frequency of updates 

that the state must provide. 

3. Components of an Initial State Plan 

Submittal and Approvability Criteria 

As noted, if a state is unable to 

prepare and submit a complete plan by 

June 30, 2016, the state must make an 

initial submittal by that date. To be 

approved, the EPA proposes that the 

initial plan must address all 

components of a complete plan, 

including identifying which 

components are not complete. For 

incomplete components, an approvable 

initial submittal must contain a 

comprehensive roadmap outlining the 

path to completion, including 

milestones and dates. We recognize that 

certain options that states may choose 

involve more analytic effort to precisely 

demonstrate sources of emission 

reductions than other options. 

The EPA is proposing that the state 

must provide an opportunity for public 

comment on a substantial draft of its 

initial submittal. The EPA proposes that 

this public comment opportunity will 

not be governed by the procedural 

requirements of the framework 

regulations that apply to the state’s 

adoption of a complete plan, such as the 

requirement that the state hold a public 

hearing. 40 CFR 60.23(c)–(f). An initial 

plan might not include any legally 

enforceable provisions that the state 

would have adopted through its 

administrative or legislative processes, 

which generally provide for public 

input. Therefore, to ensure that the 

public has an opportunity to understand 

and inform the initial plan, the EPA is 

proposing that prior to submittal on 

June 30, 2016 the state must have 

provided a reasonable opportunity for 

public comment on a substantial draft of 

the initial submittal, with notice to the 

EPA of that comment period. The EPA 

can use this comment opportunity to 

advise the state whether it is on track to 

submit an approvable initial plan. When 

the state submits its initial plan, it must 

provide the EPA with a response to any 

significant comments it received on 

issues relating to the approvability of 

the initial plan so that the EPA can fully 

assess whether it is approvable. 

To be approvable, the initial plan 

must include the following information: 

• A description of the plan approach 

and progress to date in developing a 

complete plan. 

• Initial quantification of the level of 

emission performance that will be 

achieved through the plan. 

• A commitment to maintain existing 

measures that limit or avoid CO2

emissions (e.g., renewable energy 


sroberts on DSK5SPTVN1PROD with PROPOSALS
34916 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

289Regional Greenhouse Gas Initiative 

Memorandum of Understanding, available at 

http://rggi.org/design/history/mou. Two states 

subsequently signed the original MOU in early 2007 

and a third joined the program later that year 

through an amendment of the MOU; one of the 

original states withdrew from the MOU in late 2011. 

290The model rule specified elements that needed 

to be consistent across states for the program to 

function, as well as areas where state rules could 

differ (e.g., the method used for allocating CO2

allowances). For more information, see Regional 

Greenhouse Gas Initiative Model Rule, available at 

http://rggi.org/docs/ProgramReview/_

FinalProgramReviewMaterials/Model_Rule_

FINAL.pdf. 

standards, unit-specific limits on 

operation or fuel utilization), at least 

until the complete plan is approved. 

• A comprehensive roadmap for 

completing the plan, including process, 

analytical methods, and schedule (with 

milestones) specifying when all 

necessary plan components will be 

complete (e.g., demonstration of 

projected plan performance; 

implementing legislation, regulations 

and agreements; any necessary 

approvals). 

• Identification of existing programs, 

if any, the state intends to rely on to 

meet its emission performance level. 

• Identification of executed 

agreements with other states (e.g., 

memorandum of understanding (MOU)), 

if a multi-state approach is being 

pursued. 

• A commitment to submit a 

complete plan by no later than the 

applicable required date and 

explanation of actions the state will take 

to show progress in addressing 

incomplete plan components. 

• A description of all steps the state 

has already taken in furtherance of 

actions needed to finalize a complete 

plan (e.g., copies of draft or proposed 

regulations, draft or introduced 

legislation, or draft implementation 

materials). 

• Evidence of an opportunity for 

public comment and a response to any 

significant comments received on issues 

relating to the approvability of the 

initial plan. 

The EPA is soliciting comment on 

whether there are other elements that a 

state must include in its initial 

submittal to qualify for a date extension. 

Specifically, the EPA requests comment 

on whether the guidelines should 

require a state to have taken significant, 

concrete steps toward adopting a 

complete plan for the initial plan to be 

approvable. For example, while it may 

be difficult for a state to complete its 

administrative or legislative process 

within thirteen months, it may be 

reasonable to require that a state must 

document that it has at least proposed 

any necessary regulations and 

introduced any necessary legislation 

within the first thirteen months to 

qualify for additional time to submit a 

complete plan. 

For states participating in a multistate program, the initial submittal 

should include executed agreements 

among the participating states and a 

road map for both design of the multistate program and its implementation at 

the state level. The RGGI provides an 

example of such an approach. The RGGI 

participating states signed a 

Memorandum of Understanding (MOU) 

in December 20, 2005, in which the 

states ‘‘express[ed] their mutual 

understandings and commitments’’.289

The MOU included a detailed outline of 

the multi-state emission budget trading 

program, which served as a guide for 

drafting a model rule. The MOU also 

included commitments by the 

participating states to draft and finalize 

the model rule by specified dates, and 

a commitment to seek to establish in 

statute and/or regulation a program 

materially consistent with the model 

rule in each state by a specified date.290

The MOU also included a commitment 

to launch the program by January 1, 

2009 in all states and specified a process 

for establishing a non-profit 

organization to assist the states in 

administering the regional aspects of the 

program. In addition, prior to execution 

of the MOU, the RGGI states committed, 

through letters from the Governors of 

participating states, to engage in the 

development of a market-based program 

to reduce CO2 emissions from power 

plants. This was followed by 

publication of an action plan for tasks 

leading up to agreement on the basic 

structure of the program, which was 

ultimately formalized in the MOU. 

4. Process for EPA Review of State Plans 

Following the June 30, 2016, deadline 

for state plan submittals, the EPA will 

review plan submittals for 

approvability. For a state that submits 

an initial state plan by June 30, 2016, 

and requests an extension of the 

deadline for the submission of a 

complete state plan, the EPA will 

determine if the initial plan submittal 

meets the minimum requirements for an 

initial state plan. If it meets the 

minimum requirements for an initial 

state plan, as specified in the emission 

guidelines, the state’s request for a 

deadline extension to submit a complete 

plan will be deemed granted, and the 

complete plan must be submitted to the 

EPA by no later than June 30, 2017 or 

June 30, 2018 as appropriate. 

After receipt of a complete plan 

submittal, the EPA proposes that the 

agency will review the plan and, within 

twelve months, approve or disapprove 

the plan through a notice-and-comment 

rulemaking process, similar to that used 

for approving state implementation plan 

submittals under section 110 of the 

CAA. The framework regulations 

currently provide for the EPA to act on 

a complete plan within four months. 40 

CFR 60.27(b). The EPA proposes that for 

plans under these guidelines, the agency 

will act on a complete plan within 

twelve months to provide adequate time 

for rulemaking procedures. 

Currently, the EPA’s framework 

regulations do not explicitly provide for 

the EPA to use the different forms of 

approval actions Congress introduced 

into the SIP program in the 1990 Clean 

Air Act Amendments. The EPA is taking 

comment on whether, for complete state 

plans under these guidelines, the agency 

may use two approval mechanisms 

provided for in CAA sections 110(k)(3) 

and (4), 42 U.S.C. 7410(k)(3) and (4). 

CAA section 111(d)(1) provides that the 

EPA shall establish ‘‘a procedure similar 

to that provided by section 7410 of this 

title [section 110 of the Act].’’ The EPA 

is considering whether to update the 

procedures for acting on complete state 

plans under the guideline to reflect the 

enhancements Congress included in 

CAA section 110 for agency actions on 

state implementation plans. 

The first mechanism is a partial 

approval/partial disapproval. Where a 

CAA section 111(d) plan includes 

severable provisions, some of which are 

approvable and some of which are not, 

the EPA is taking comment on whether 

the agency should interpret the CAA as 

providing the flexibility to approve 

those elements that meet the 

requirements of this guideline, while 

disapproving those elements that do 

not. Any plan that is partially approved 

and partially disapproved would not 

fully discharge the state’s obligation to 

submit a fully approvable plan, but the 

partial approval would make federally 

enforceable those elements of the state’s 

plan that comply with these guidelines. 

The second mechanism is a 

conditional approval. Where a CAA 

section 111(d) plan is substantially 

approvable and requires only minor 

amendments to fully meet the 

requirements of these guidelines, the 

EPA is taking comment on whether the 

agency should interpret the CAA as 

providing the flexibility to approve that 

plan on the condition that the state 

commits to curing the minor 

deficiencies within one year. Any such 

conditional approval would be treated 

as a disapproval if the state fails to 

comply with its commitment. During 

the year following the conditional 

approval while the state works to cure 


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the deficiency identified in the 

condition, the state’s plan would be 

federally enforceable. 

The EPA has seen that these 

mechanisms have proven useful when 

reviewing and acting on state 

implementation plan submittals under 

CAA section 110. They allow the state, 

the EPA, and citizens to enforce good 

elements of plans or plans that are 

substantially complete while the state 

and the EPA work together to put in 

place a fully approvable plan. The 

agency notes that complete plan 

submittals under these guidelines, like 

SIPs that implement air quality 

standards, also may contain multiple 

program elements. 

5. Failure To Submit a Complete Plan 

If a state fails to submit a complete 

plan by the applicable deadline, the 

EPA will notify the state by letter of its 

failure to submit. The EPA will publish 

a Federal Register notice informing the 

public of any such notifications. When 

appropriate, the agency may batch the 

publication of such notices periodically 

to simplify publication. 

6. Modification of an Approved State 

Plan 

During the course of implementation 

of an approved state plan, a state may 

wish to update or alter one or more of 

the enforceable measures in the state 

plan, or replace certain existing 

measures with new measures. The EPA 

proposes that the state may revise its 

state plan provided that the revision 

does not result in reducing the required 

emission performance for affected EGUs 

specified in the original approved plan. 

In other words, no ‘‘backsliding’’ on 

overall plan emission performance 

through a plan modification would be 

allowed. 

If the state wishes to revise 

enforceable measures in its approved 

state plan, the EPA proposes that the 

state must submit the revised 

enforceable measures to the EPA and 

demonstrate that the revised set of 

enforceable measures in the modified 

plan will result in emission 

performance at affected EGUs that is 

equivalent to or better than the level of 

emission performance required by the 

original state plan. In the case of minor 

changes to enforceable measures, this 

showing may be a simple explanation of 

why the changes will not alter the 

emission performance of affected EGUs 

under the state plan, or will clearly 

improve the emission performance of 

affected EGUs under the state plan. In 

the case of more substantive changes to 

enforceable measures, or substitution of 

a new measure for an old measure, new 

projections of emission performance 

under the modified plan would be 

needed to demonstrate that the modified 

plan will meet the required level of 

emission performance for affected EGUs 

specified in the original approved plan. 

The EPA requests comment on whether, 

for such new projections of emission 

performance, the projection methods, 

tools, and assumptions used should 

match those used for the projection in 

the original demonstration of plan 

performance, or should be updated to 

reflect the latest data and assumptions, 

such as assumptions for current and 

future economic conditions and 

technology cost and performance. 

7. Plan Templates and Electronic 

Submittal 

The EPA is seeking comment on the 

creation of a template for initial and 

complete state plan submittals. A plan 

template would provide a framework 

that includes all of the necessary 

components for an initial and complete 

submittal that could be populated by 

states. This could assist states in 

compiling their plan submittals and 

streamline EPA review by assuring 

greater consistency in the format and 

organization of submittals. This would 

provide greater certainty for states about 

what they need to include in a submittal 

and allow the EPA to provide a quicker 

response to states about the 

completeness and approvability of 

submittals. We are further seeking 

comment on whether a template may be 

more appropriate for initial plan 

submittals than complete plans. Initial 

plan submittals are likely to be more 

similar across states, compared to 

complete plans, which may include a 

diverse range of components, depending 

on the state plan approach. 

The EPA is also seeking comment on 

whether it should provide for, or 

require, electronic submittal of initial 

and complete plans. It is the EPA’s 

experience that the electronic submittal 

of information increases the ease and 

efficiency of data submittal and data 

accessibility. We note that a number of 

states have requested an electronic 

submittal process for state 

implementation plans (SIPs) under CAA 

section 110, and the EPA has 

implemented a pilot program with a 

number of states for electronic submittal 

of such plans. The Electronic State 

Implementation Plan Submission Pilot 

(eSIPS) includes an EPA-state 

workgroup that has developed and will 

evaluate an electronic submission 

process. This pilot will use the EPA’s 

Central Data Exchange (CDX) electronic 

submission system. We are seeking 

comment on the suitability of such an 

approach for submittal of state plans 

under CAA section 111(d). 

F. State Plan Considerations 

The EPA is proposing to give states 

broad discretion to develop plans that 

best suit their circumstances and policy 

objectives. In developing its plan, a state 

will need to make a number of decisions 

that will require careful consideration, 

in order to ensure that its plan both 

meets the state’s policy objectives and is 

approvable by the EPA. In this section, 

we identify several key decision points 

and factors that states should consider 

when developing their plans. 

The EPA has also prepared a TSD, 

titled ‘‘State Plan Considerations,’’ that 

provides further information on these 

topics. The agency is seeking comment 

on the contents of this TSD and all 

aspects of the state plan decision points 

and factors below. 

1. Affected Entities Other Than Affected 

EGUs 

A state will need to identify each 

affected entity responsible for meeting 

compliance obligations under its plan 

and the means by which compliance 

with each plan requirement will be met, 

as well as demonstrate that it has the 

legal authority to subject such entities to 

the federally enforceable requirements 

specified in its state plan. We are 

proposing that affected entities in an 

approvable state plan may include: An 

owner or operator of an affected EGU, 

other affected entities with 

responsibilities assigned by a state (e.g., 

an entity that is regulated by the state, 

such as an electric distribution utility, 

or a private or public third-party entity), 

and a state agency, authority or entity. 

We are seeking comment on other 

appropriate examples of affected entities 

beyond the affected EGUs. 

While the EPA seeks to provide states 

with broad discretion to develop plans 

that best suit their circumstances and 

policy objectives, a plan that assigns 

responsibility to affected entities other 

than affected EGUs may be more 

challenging to implement and enforce 

than a plan with requirements assigned 

only to affected EGUs. 

Furthermore, it may be more 

challenging for a state to demonstrate 

that it has sufficient legal authority to 

subject such affected entities other than 

affected EGUs to the federally 

enforceable requirements specified in its 

state plan. We seek comment on 

whether the EPA should provide 

guidance on enforceability 

considerations related to requirements 

in a state plan for affected entities other 

than EGUs (and if so, which such 

entities). The State Plan Considerations 


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291For example, in such instances a significant 

shift to NGCC generation prior to 2012 may result 

in a lower potential for further re-dispatch to these 

units, as witnessed in the 2012 base period data. 

This would influence the calculated rate-based 

emission goal for the state, reducing the percentage 

improvement required relative to the base period 

CO2 emission rate. 

292An ‘‘existing measure’’ refers to a state or 

utility requirement, program, or measure that is 

currently ‘‘on the books.’’ For the purposes of this 

discussion, this may include a legal requirement 

that includes current and future obligations or 

current programs and measures that are in place 

and are anticipated to be continued or expanded in 

the future in accordance with established plans. 

Existing measures may have past, current, and 

future impacts on EGU CO2 emissions. 

293We are also proposing that this proposed 

limitation would not apply to existing renewable 

energy requirements, programs and measures 

because existing renewable energy generation prior 

to the date of proposal of the emission guidelines 

was factored into the state-specific CO2 goals as part 

of building block 3. 

TSD provides illustrative examples of 

possible entities and legal mechanisms. 

2. Treatment of Existing State Programs 

a. Framing Considerations 

Many state officials and stakeholders 

have said that the EPA should avoid 

structuring the CAA section 111(d) 

emission guidelines in a way that would 

disadvantage states that already have 

adopted programs that reduce CO2

emissions from EGUs. The EPA agrees 

with that policy principle. 

There is much less agreement among 

states and stakeholders on the specifics 

of how existing state programs should 

be treated in a demonstration that a 

proposed state plan will achieve the 

required level of emission performance. 

The EPA, starting from recent 

historical data, has identified the 

affected EGU emission performance 

improvements and resulting average 

emission performance levels for affected 

EGUs that are achievable, considering 

cost, in each state over the 2020–2029 

period, with achievement of the final 

CO2 emission performance level by 

2030. 

As explained in Section VII above, the 

EPA’s proposed state-specific goals 

reflect actions that many states have 

already taken to reduce or avoid EGU 

CO2 emissions. CO2 emission reductions 

due to shifts to lower CO2-emitting 

power generation are also represented in 

the 2012 base period that was used to 

assess certain building blocks that are 

applied in calculating a state emission 

performance goal.291

The agency recognizes that states that 

have already shifted toward lower 

carbon-intensity generation or ramped 

up demand-side EE programs are better 

positioned to meet state-specific goals. 

For example, states where significant 

shifts in generation to NGCC units have 

already occurred would be closer to the 

generation mix reflected in the state 

goals than states where NGCC capacity 

is not yet being operated to the same 

degree. Likewise, states with relatively 

well-established demand-side EE 

programs would be able to build on 

those programs more quickly than states 

with less established programs, and 

would be closer to, or in some cases 

already achieving, the level of demandside energy efficiency reflected in the 

state goals. 

b. Proposed Approach for Treatment of 

Existing State Programs and Measures in 

an Approvable State Plan 

The EPA is proposing that existing 

state programs, requirements, and 

measures,292 may qualify for use in 

demonstrating that a state plan will 

achieve the required level of emission 

performance, provided they meet the 

approvability requirements in the 

emission guidelines (summarized above 

in Section VIII.C) and relevant 

requirements for plan components in 

the emission guidelines (described 

above in Section VIII.D). Several options 

for treatment of existing state programs 

and measures are described below. 

Specifically, the EPA is proposing 

that, for an existing state requirement, 

program, or measure, a state may apply 

toward its required emission 

performance level the emission 

reductions that existing state programs 

and measures achieve during a plan 

performance period as a result of actions 

taken after the date of this proposal.293

This proposed approach would 

recognize beneficial emission impacts 

from existing state programs and 

measures during a plan performance 

period. It would do so in a way that may 

be generally compatible with the 

forward-looking methodology that the 

EPA used to propose state emission 

performance goals based on the BSER. 

By making actions taken after proposal 

eligible to help meet a state’s required 

emission performance level, this 

approach would support early beneficial 

emission-reducing actions. This option 

would ensure that actions taken after 

proposal of the emission guidelines and 

prior to 2020 as a result of requirements 

in a state plan, could be recognized as 

contributing toward meeting a state’s 

required emission performance level for 

affected EGUs. 

In general, the agency has identified 

two broad options for treatment of 

existing state programs and measures. 

As noted above, the EPA proposes that 

emission reductions that existing state 

requirements, programs and measures 

achieve during a plan performance 

period as a result of actions taken after 

a specified date may be recognized in 

determining emission performance 

under a state plan. While proposing that 

the ‘‘specified date’’ would be the date 

of proposal of these emission 

guidelines, the EPA also requests 

comment on the following alternatives: 

The start date of the initial plan 

performance period, the date of 

promulgation of the emission 

guidelines, the end date of the base 

period for the EPA’s BSER-based goals 

analysis (e.g., the beginning of 2013 for 

blocks 1–3 and beginning of 2017 for 

block 4, end-use energy efficiency), the 

end of 2005, or another date. 

For this option, we are seeking 

comment on the point in time after 

which such actions should be able to 

qualify for use during a plan 

performance period, considering the 

method used to set state goals. Whether 

this option is consistent in practice with 

the EPA’s application of the BSER may 

depend on the date or dates that are 

applied for qualifying actions under 

existing state programs, requirements, 

and measures. For example, 

implementation of measures subsequent 

to the proposal or promulgation of the 

emission guidelines may be consistent 

with a forward-looking goal-setting 

approach, as these actions may be 

necessary to meet a required level of 

emission performance during the plan 

performance period or will put a state 

in a better position to meet the required 

level of performance. An example is the 

EPA’s treatment of end-use energy 

efficiency potential in state goal-setting, 

where the energy savings achievable 

during the initial plan performance 

period are premised in part on a 

ramping up of end-use energy efficiency 

programs and cumulative energy 

savings prior to the beginning of the 

plan performance period. Earlier dates 

may also be consistent with a forwardlooking goal-setting approach, if the 

goal-setting approach is premised in 

part on actions that could be taken prior 

to the initial plan performance period. 

However, inconsistency issues may 

arise if the selected date is not 

adequately synchronized with the goalsetting method. The EPA requests 

comment on whether there is a rational 

basis for choosing a date that predates 

the base period from which the EPA 

used historical data to derive state goals. 

The agency generally requests comment 

on the appropriate date to select under 

this option. 

The EPA also solicits comment on a 

second broad option. This option would 

recognize emission reductions that 

existing state requirements, programs 


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294We are also proposing that RE and demandside EE measures could be used under a mass-based 

portfolio approach in an approvable state plan. 

However, the focus of this section is limited to 

application of such measures under a rate-based 

approach. 

295This could include an individual affected EGU 

or group of affected EGUs if a rate-based averaging 

or trading approach is used. 

and measures achieved starting from a 

specified date prior to the initial plan 

performance period, as well as emission 

reductions achieved during a plan 

performance period. The specified date 

could be, for example: The date of 

promulgation of the emission 

guidelines; the date of proposal of the 

emission guidelines; the end date of the 

base period for the EPA’s BSER-based 

goals analysis (e.g., the beginning of 

2013 for blocks 1–3 and the beginning 

of 2017 for block 4, end-use energy 

efficiency); the end of 2005; or another 

date. 

The EPA requests comment on this 

option—that emission reduction effects 

that occur prior to the beginning of the 

initial plan performance period could be 

applied toward meeting the required 

level of emission performance in a state 

plan. This approach would enable a 

state to count emission improvements 

achieved by state programs prior to 2020 

toward its interim goal, allowing the 

state to begin demonstrating emission 

performance earlier and follow a more 

gradual emission improvement 

trajectory during the interim 

performance period of 2020–2029. This 

approach would in effect allow higher 

emissions during the 2020–2029 period 

than would occur under the proposed 

approach (i.e., requiring less emission 

performance improvement during that 

period). The rationale for this approach 

would be that higher emissions in 2020– 

2029 would be offset by pre-2020 

emission reductions not required by the 

CAA section 111(d) program. However, 

total emissions to the atmosphere would 

likely be greater under this approach, 

unless the pre-2020 emission reductions 

that can be counted toward the state 

goal are limited to reductions that 

would not have occurred in the absence 

of the CAA section 111(d) program. To 

the extent that states are able to both 

adopt and implement new requirements 

earlier than 2020 (e.g., by 2018 or 2019), 

this approach could provide an 

incentive for earlier emission 

reductions. The agency requests 

comment on whether pre-2020 

implementation of new requirements 

would be practical for states. The 

agency generally requests comment on 

this approach, including the conditions 

that should apply to pre-2020 emission 

reductions that would count toward the 

state goal. 

The agency also requests comment on 

the alternative dates listed above in 

connection with this option. We also 

request comment on whether this option 

is inconsistent with the forward-looking 

method that the EPA has proposed for 

establishing state goals based on the 

application of the BSER. 

The agency is seeking comment on 

whether some variation of this approach 

could be justified as consistent with the 

EPA’s proposed goal-setting approach, 

as well as the general concept of the 

BSER and its application in establishing 

state goals. In particular, we are seeking 

comment on whether the emission 

effects of actions that are taken after 

proposal or promulgation of the 

emission guidelines or the approval of 

a state plan, but which occur prior to 

the beginning of the initial state plan 

performance period, could be applied 

toward meeting the required level of 

emission performance in a state plan. 

c. Application of Options Under RateBased and Mass-Based Plan Approaches 

Under a rate-based approach, the 

options described above would address 

the eligibility date for qualifying 

demand-side EE measures that, through 

MWh savings, avoid CO2 emissions 

from affected EGUs. Measures installed 

after the eligibility date could generate 

MWh savings during a plan 

performance period, and related 

avoided CO2 emissions, that could be 

applied toward meeting a required ratebased emission performance level. 

Under the proposed option, the 

eligibility date would be the date of 

these proposed emission guidelines. For 

example, under this approach, new 

demand-side EE measures installed in 

2015 or later to meet an existing, on-thebooks energy efficiency resource 

standard (EERS) would be a qualifying 

measure. However, only MWh savings 

beginning in 2020 and related avoided 

CO2 emissions could be applied toward 

meeting a required rate-based emission 

performance level. 

Under a mass-based approach, the 

options described above would be 

applied when establishing a reference 

case scenario projection that is used to 

translate a rate-based goal to a massbased goal. For example, demand-side 

EE measures after a respective eligibility 

date would not be included in the 

scenario that is used to project CO2

emissions from affected EGUs when 

establishing a translated mass-based 

emission goal. This could be achieved 

by not including the incremental 

requirements of an end-use EERS 

requirement in a reference case 

projection, beginning at a specified date. 

These considerations are addressed in 

more detail in Section VIII.F.7. below 

and in the Projecting CO2 Emission 

Performance in State Plans TSD. 

3. Incorporating RE and Demand-Side 

EE Measures Under a Rate-Based 

Approach 

We are proposing that RE and 

demand-side EE measures may be 

incorporated into a rate-based approach 

through an adjustment or tradable credit 

system applied to an EGU’s reported 

CO2 emission rate.294 Under such a 

process, measures that avoid EGU CO2

emissions from affected EGUs, such as 

quantified and verified end-use energy 

savings and renewable energy 

generation, could be credited toward a 

demonstrated CO2 emission rate for 

EGU compliance purposes or used by 

the state to administratively adjust the 

average CO2 emission rate of affected 

EGUs when demonstrating achievement 

of the required rate-based emission 

performance level in a state plan. 

Under this approach, affected 

EGUs 295 could comply with a CO2

emission rate limit in part through the 

use of credits for actions that avoid CO2

emissions from affected EGUs. If a state 

is implementing a portfolio approach, 

then the state could administratively 

adjust the average CO2 emission rate of 

affected EGUs through a similar process, 

provided that the CO2-avoiding 

measures are enforceable elements of 

the state plan. 

We are seeking comment on different 

approaches for providing such crediting 

or administrative adjustment of EGU 

CO2 emission rates, which are 

elaborated further in the State Plan 

Considerations TSD. 

Credits or adjustment might represent 

avoided MWh of electric generation or 

avoided tons of CO2 emissions. The 

approach chosen could have significant 

implications for the amount of 

adjustment or credit provided for RE 

and demand-side EE measures. If 

adjustment or credits represent avoided 

MWh, they would be added to the 

denominator when determining an 

adjusted lb CO2/MWh emission rate. If 

adjustment or credits represent avoided 

CO2 emissions, they would be 

subtracted from the numerator when 

determining an adjusted lb CO2/MWh 

emission rate. 

A MWh crediting or adjustment 

approach implicitly assumes that the 

avoided CO2 emissions come directly 

from the particular affected EGU (or 

group of EGUs) to which the credits are 


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296As a result, the assumed avoided CO2

emissions from an individual MWh of energy 

savings or MWh of generation from renewable 

energy will differ based on the reported CO2

emission rate of the individual EGU to which the 

MWh is applied as an adjustment to its MWh 

output. 

297 Deemed savings are measure-specific 

stipulated values based on historical and verified 

data. Unlike other EM&V approaches, deemed 

savings approaches involve limited or no 

measurement activities, and are therefore a common 

and relatively low-cost strategy for documenting 

energy savings. 

298 Gross savings are the change in energy use 

(MWh) and demand (MW) that results directly from 

program-related actions taken by program 

participants, regardless of why they participated in 

a program. Net savings refer to the change in energy 

use and demand that is directly attributable to a 

particular energy efficiency program. 

applied. It assumes, in effect, that an 

additional emission-free MWh is being 

generated by that respective EGU, and 

that the RE or demand-side EE measure 

reduces CO2 emissions from that 

individual EGU or group of EGUs.296 In 

practice, the average or marginal CO2

emission rate in the power pool or 

identified region—representing the 

avoided CO2 emissions from the 

generating sources being displaced by a 

MWh of energy savings or a MWh of 

renewable energy generation—could 

differ significantly from the calculated 

avoided CO2 emissions derived by 

adjusting the MWh output of an affected 

EGU. 

An alternative approach is to provide 

an adjustment based on the estimated 

CO2 emissions that are avoided from the 

power pool or identified region as a 

result of RE and demand-side EE 

measures. This approach implicitly 

assumes that the avoided CO2 emissions 

come from the electric power pool or 

other identified region as a whole, 

rather than an individual EGU. The 

avoided CO2 emissions are determined 

based on the MWh saved or generated, 

multiplied by a CO2 emission rate for 

the power pool or region. This CO2

emission rate could be based on the 

average or marginal emission rate in the 

power pool or region, or could be based 

on the emission rate that represents the 

required rate-based emission 

performance level in the plan. We invite 

comment on each of these possible 

approaches. 

In addition, because some of the CO2

emissions avoided through RE and 

demand-side EE measures may be from 

non-affected EGUs, we are seeking 

comment on how this might be 

addressed in a state plan, whether when 

adjusting or crediting CO2 emission 

rates of affected EGUs based on the 

effects of RE and demand-side EE 

measures or otherwise. How these 

dynamics might be addressed, both in 

projections of plan performance and in 

actual demonstration of performance 

achieved under a plan, is further 

discussed in the State Plan 

Considerations TSD. 

4. Quantification, Monitoring, and 

Verification of RE and Demand-Side EE 

Measures 

A key consideration for state plans is 

the process and requirements under a 

state plan for quantifying, monitoring, 

and verifying the effect of RE and 

demand-side EE measures that result in 

electricity generation or electricity 

savings. 

The EPA is proposing that a state plan 

that includes enforceable RE and 

demand-side EE measures must include 

an evaluation, measurement, and 

verification (EM&V) plan that explains 

how the effect of these measures will be 

determined in the course of plan 

implementation. An EM&V plan will 

specify the analytic methods, 

assumptions, and data sources that the 

state will employ during the state plan 

performance periods to determine the 

energy savings and energy generation 

related to RE and demand-side EE 

measures. An EM&V plan would be 

subject to EPA approval as part of a state 

plan. As discussed below, the EPA 

intends to develop guidance on 

acceptable EM&V methods that could be 

incorporated in an approvable EM&V 

plan that is included as part of an 

approvable state plan. 

Utilities and states have conducted 

ongoing EM&V of demand-side EE and 

RE measures and programs for several 

decades. Current practice with EM&V 

for RE and demand-side EE programs in 

the U.S. is primarily defined by state 

public utility commission (PUC) 

requirements for customer-funded 

energy efficiency and renewable energy 

programs, as well as related compliance 

and reporting requirements for EERS 

and renewable portfolio standards 

(RPS). 

The level of PUC oversight of 

demand-side EE programs varies from 

state to state, but this oversight process 

has generated the majority of the 

industry guidance and protocols for 

documenting energy savings from EE 

programs. Typically, impact evaluation 

reports are responsive to requirements 

established by PUCs and submitted 

(usually annually) for PUC review, 

approval, and use in resource planning 

and performance assessment. These 

PUC requirements generally rely upon a 

well-defined set of industry-standard 

practices and procedures. In states with 

the most experience implementing and 

overseeing demand-side EE programs, 

this typically includes: Use of one or 

more industry-standard EM&V protocols 

or guidelines; use of ‘‘deemed savings 

values,’’ 297 where appropriate, for wellunderstood demand-side EE measures; 

consideration of local factors, such as 

climate, building type, and occupancy; 

involvement of stakeholders and 

solicitation of expert advice regarding 

EM&V processes and resulting energy 

savings impacts; conduct of EM&V 

activities (e.g., direct equipment 

measurements, application of deemed 

savings, and reporting of impacts) on a 

regular basis; and provision of interim 

and annual reporting of achieved energy 

savings. 

Despite this well-defined and 

generally accepted set of industry 

practices, many states with energy 

efficiency programs use different input 

values and assumptions in applying 

these practices (e.g., net versus gross 

savings,298 run-time of equipment, 

measure lifetime). This can result in 

significant differences in claimed energy 

savings values for similar energy 

efficiency measures between states and 

utilities, even when the same measure 

type is installed under otherwise 

identical circumstances. In response to 

a growing awareness of this lack of 

cross-state comparability, policy 

makers, regulatory agencies, and other 

stakeholders are increasingly advocating 

for the use of common evaluation 

approaches across jurisdictions. A 

number of states and utilities in 

different regions of the country are 

already working to develop such 

common approaches. 

For RE measures and programs, 

EM&V employed by states and utilities 

commonly relies upon a set of standard 

practices and procedures, such as the 

use of revenue-quality meters for 

quantifying RE generation. As a result, 

existing state and utility requirements 

and processes for quantification, 

monitoring, and verification of RE 

programs and measures generally 

provide a solid foundation for minimum 

requirements or guidance established by 

the EPA for state plans. 

For both RE and demand-side EE 

measures included in state plans, 

additional information and reporting 

may be necessary to accurately quantify 

the avoided CO2 emissions associated 

with these measures, such as 

information on the location and the 

hourly, daily, or seasonal basis of 

renewable energy generation or energy 

savings. 

Current state and utility EM&V 

approaches for RE and demand-side EE 

programs and mandates are discussed in 

more detail in the State Plan 


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299Section V.A.4 of the State Plan Considerations 

TSD includes a detailed description of these EM&V 

parameters. 

300A list of these protocols is provided in Section 

V.A.3.1 of the State Plan Considerations TSD. 

Considerations TSD. We are seeking 

comment on the suitability of these 

approaches in the context of an 

approvable state plan, and on whether 

harmonization of state approaches, or 

supplemental actions and procedures, 

should be required in an approvable 

state plan. In particular, we intend to 

establish guidance for acceptable 

quantification, monitoring, and 

verification of RE and demand-side EE 

measures for an approvable EM&V plan, 

and are seeking comment on critical 

features of such guidance, including 

scope, applicability, and minimum 

criteria.299 We are also seeking comment 

on the appropriate basis for and 

technical resources used to establish 

such guidance, including consideration 

of existing state and utility protocols, as 

well as existing international, national, 

and regional consensus standards or 

protocols.300 The EPA’s goal in 

developing such guidance is to assure 

that it is consistent with industrystandard EM&V approaches for both RE 

and demand-side EE measures and 

programs, leverages the EM&V resources 

and infrastructure already in place in 

many states, and strikes a reasonable 

balance between EM&V costs, rigor, and 

the value of resulting information, while 

considering the specific use of such 

information in assessing avoided CO2

emissions from affected EGUs. 

In developing guidance, the agency 

does not intend to limit the types of RE 

and demand-side EE measures and 

programs that can be included in a state 

plan, provided that supporting EM&V is 

rigorous, complete, and consistent with 

the EPA’s guidance. This approach 

recognizes differences among RE and 

demand-side EE programs and measures 

with respect to implementation history 

and experience, existence of applicable 

EM&V protocols and methods, and the 

nature and type of program oversight 

(e.g., whether or not a program is subject 

to PUC oversight). The EPA is 

requesting comment on the merits of 

this approach, including whether such 

guidance should identify types of RE 

and demand-side EE measures and 

programs for which evaluation of results 

is relatively straightforward and which 

are appropriate for inclusion in a state 

plan. Such approaches might be subject 

to streamlined review of EM&V 

protocols included in an approvable 

state plan, provided that such protocols 

are applied in accordance with industry 

best practices. For example, many 

utilities have implemented a similar 

core set of RE and demand-side EE 

measures and programs for utility 

customers. For these types of measures 

and programs, a substantial base of 

experience has been established 

nationally for the evaluation of measure 

and program outcomes. Other types of 

measures and programs, such as those 

that seek to alter consumer and building 

occupant behavior might pose 

quantification and verification 

challenges. Still other types of 

measures, such as state energy-efficient 

appliance standards and building codes, 

have not typically been subject to 

similar evaluation of energy savings 

results. These types of approaches might 

have substantial impacts, and the EPA 

does not want to discourage their 

implementation in state plans, but they 

might require development of 

appropriate quantification, monitoring, 

and verification protocols. The EPA and 

its federal partners intend to discuss the 

development of appropriate EM&V 

protocols for such measures with states 

in the coming years. 

As an alternative to the EPA’s 

proposed approach of allowing a broad 

range of RE and demand-side EE 

measures and programs to be included 

in state plans, provided that supporting 

EM&V documentation meets applicable 

minimum requirements, the EPA is 

requesting comment on whether 

guidance should limit consideration to 

certain well-established programs, such 

as those characterized in Section 

V.A.4.2.1 of the State Plan 

Considerations TSD. 

5. Reporting and Recordkeeping for 

Affected Entities Implementing RE and 

Demand-Side EE Measures 

If a state plan incorporates RE and 

demand-side EE measures under a ratebased approach or implements a massbased portfolio approach with such 

measures, reporting and recordkeeping 

requirements for an approvable plan 

would differ from those applicable to an 

affected EGU. For example, these 

requirements may include compliance 

reporting by an electric distribution 

utility subject to an EERS or RPS. They 

may also include reporting by a 

vertically integrated utility 

implementing an approved integrated 

resource plan. In the latter instance, the 

utility might also be the owner and 

operator of affected EGUs, but 

additional reporting of quantified effects 

of RE and demand-side EE measures 

under the utility plan would be 

necessary to demonstrate emission 

performance under the state plan. In 

other instances, a state agency or entity 

or a private or public third-party entity 

might be implementing programs and 

measures that support the deployment 

of end-use energy efficiency and clean 

energy technologies that are 

incorporated into a state plan. In each 

of these instances, reporting of program 

compliance or program outcomes is a 

necessary part of an approvable plan to 

demonstrate emission performance 

under the plan. 

Examples of potential reporting 

obligations for affected entities 

implementing RE and demand-side EE 

measures in an approvable state plan are 

provided in the State Plan 

Considerations TSD. We are seeking 

comment on the examples and 

suitability of potential approaches 

described in the TSD and any other 

appropriate reporting and recordkeeping 

requirements for affected entities 

beyond affected EGUs. 

6. Treatment of Interstate Effects 

The electricity system and wholesale 

electricity markets are interstate in 

nature. EGUs in one state provide 

electricity to customers in neighboring 

states. Power companies often own 

EGUs in more than one state and 

manage them as a system. EGUs are 

dispatched both within and across state 

borders. 

Similarly, programs and measures in 

a state plan, such as RE and demandside EE measures, may affect the 

performance of the interconnected 

electricity system beyond a state border. 

In addition, many state programs allow 

for actions in neighboring states to meet 

the in-state requirement or explicitly 

address CO2 emissions in neighboring 

states. For example, many state 

renewable portfolio standards allow for 

generation by qualifying renewable 

energy sources in other states to count 

toward meeting the state portfolio 

requirement. Some states also apply CO2

emission requirements related to the 

generation of power purchased by 

regulated utilities, including power 

imported from out of state. 

The EPA recognizes the complexity of 

accounting for interstate effects 

associated with measures in a state plan 

in a consistent manner, to allow states 

to take into account the CO2 emission 

reductions resulting from these 

programs while minimizing the 

likelihood of double counting. We also 

realize that interstate effects on CO2

emissions from affected EGUs could be 

attributed in different manners in the 

context of an approvable state plan. The 

EPA is seeking comment on the options 

summarized below, as well as 

alternatives. These options and 

alternatives, and how they might apply 

to both projections of plan performance 


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and reporting of achieved plan 

performance, are addressed in the State 

Plan Considerations TSD. 

The EPA is proposing that, for 

demand-side EE measures, consistent 

with the approach that the EPA used in 

determining the BSER, a state could take 

into account in its plan only those CO2

emission reductions occurring (or 

projected to occur) in the state that 

result from demand-side EE measures 

implemented in the state. The agency is 

also proposing that, for states that 

participate in multi-state plans, the 

participating states would have the 

flexibility to distribute the CO2 emission 

reductions among states in the multistate area, as long as the total CO2

emission reductions claimed are equal 

to the total of each state’s in-state 

emissions reductions that result from 

demand-side EE measures implemented 

in those states. We are also proposing 

that states could jointly demonstrate 

CO2 emission performance by affected 

EGUs through a multi-state plan in a 

contiguous electric grid region, in which 

case attribution of emission reductions 

from demand-side EE measures would 

not be necessary. We also request 

comment on whether a state should be 

able to take credit for emission 

reductions out of state due to in-state EE 

measures if the state can demonstrate 

that the reductions will not be doublecounted when the relevant states report 

on their achieved plan performance, and 

what such a demonstration should 

entail. We request comment on these 

and other approaches for taking into 

account CO2 emission reductions from 

demand-side EE measures in state plans. 

The EPA is proposing that, for 

renewable energy measures, consistent 

with existing state RPS policies, a state 

could take into account all of the CO2

emission reductions from renewable 

energy measures implemented by the 

state, whether they occur in the state or 

in other states. This proposed approach 

for RE acknowledges the existence of 

renewable energy certificates (REC) that 

allow for interstate trading of RE 

attributes and the fact that a given 

state’s RPS requirements often allow for 

the use of qualifying RE located in 

another state to be used to comply with 

that state’s RPS. 

The EPA is also seeking comment on 

how to avoid double counting emission 

reductions using this proposed 

approach. The agency is also proposing 

that states participating in multi-state 

plans could distribute the CO2 emission 

reductions among states in the multistate area, as long as the total CO2

emission reductions claimed are equal 

to the total of each state’s in-state 

emission reductions from RE measures. 

We also request comment on the option 

of allowing a state to take into account 

only those CO2 emission reductions 

occurring in its state. We are also 

proposing that states could jointly 

demonstrate CO2 emission performance 

by affected EGUs through a multi-state 

plan in a contiguous electric grid region, 

in which case attribution among states 

of emission reductions from renewable 

energy measures would not be 

necessary. We also request comment on 

whether a state should be able to take 

credit for emission reductions out of 

state due to renewable energy measures 

if the state can demonstrate that the 

reductions will not be double-counted 

when the relevant states report on their 

achieved plan performance, and on 

what such a demonstration should 

entail. We request comment on these 

and other approaches for taking into 

account CO2 emission reductions from 

renewable energy measures. 

7. Projecting Emission Performance 

As proposed, an approvable state plan 

will include a projection of CO2

emission performance by affected EGUs 

under the plan. In addition, a state plan 

that is using a mass-based goal in 

determining the required level of 

emission performance under the plan 

will include a translation of the ratebased emission goal in the emission 

guidelines to a mass-based goal. This 

translation will involve a projection of 

CO2 emissions from affected EGUs 

during the initial 2020–2029 plan 

performance period and in 2030, under 

a scenario that assumes the rate-based 

goal in the emission guidelines is met. 

The EPA is striving to find a balance 

between providing state implementation 

flexibility and ensuring that the 

emission performance required by CAA 

section 111(d) is properly defined in 

state plans and that plan performance 

projections have technical integrity. 

Each state plan must include a 

projection of CO2 emission performance 

from affected EGUs during the multiyear plan period that will result from 

implementation of the plan. Depending 

on the type of plan approach, this will 

include either a projection of the 

average CO2 emission rate achieved by 

affected EGUs or total CO2 emissions 

from affected EGUs. 

The credibility of state plans under 

CAA section 111(d) will depend in large 

part on ensuring credible and consistent 

emission performance projections in 

state plans. Therefore, the use of 

appropriate methods, tools and 

assumptions for such projections is 

critical. 

Considerations for projecting 

emission performance under a state plan 

will differ depending on the type of 

plan. This includes differences in how 

inputs to projections are derived; how 

projections are conducted, including 

tools, methods and assumptions; and 

how aspects of a plan are represented in 

these projections. 

In general, any material component of 

a state requirement or program included 

in a state plan that could affect emission 

performance by affected EGUs should be 

accurately represented in emission 

projections included in the state plan. 

For example, mass-based emission 

budget trading programs include a 

number of compliance flexibility 

mechanisms that might impact emission 

performance achieved by affected EGUs 

subject to these programs. These include 

multi-year compliance periods; the 

ability to bank allowances issued in a 

previous compliance period for use in a 

subsequent compliance period; the use 

of out-of-sector project-based emission 

offsets; and cost-containment allowance 

reserves that make additional 

allowances available to the market if 

pre-established allowance price 

thresholds are achieved. As a result, 

annual emissions from affected sources 

subject to an emission budget trading 

program often differ from the 

established annual emission budget for 

affected sources. In addition, these 

programs may be multi-sector in nature, 

regulating emissions for source 

categories in addition to EGUs. As a 

result, emission projections in state 

plans will need to accurately account 

for and represent these compliance 

flexibilities, as well as the scope of 

affected sources if they are broader than 

EGUs affected under CAA section 

111(d). Similarly, other types of state 

programs, such as RPS, may include 

flexibility mechanisms or other 

provisions, such as alternative 

compliance payment mechanisms, 

banking, and limits on total ratepayer 

impact, that affect the ultimate amount 

of electricity generation required under 

the portfolio standard. These 

considerations for different types of 

state programs are discussed in more 

detail in the Projecting EGU CO2

Emission Performance in State Plans 

TSD. 

In general, as with projections used to 

determine a mass-based goal, 

projections of emission performance 

under a state plan could be conducted 

using historical data and parameters for 

estimating the future impact of 

individual state programs and measures. 

Alternatively, a projection could 

include modeling, such as use of a 

capacity planning and dispatch 


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301 In many cases, this approach will also require 

the development of parameters for estimating the 

future effect of individual state programs and 

measures, for use as input assumptions for 

modeling. 

model.301 This latter approach would be 

able to capture dynamic interactions 

within the electricity sector, based on 

system operation and market forces, 

including interactions among state 

programs and measures and the 

dynamics of market-based measures. 

These considerations, and 

considerations for projecting emission 

performance under different types of 

state plan approaches, are discussed in 

detail in the Projecting EGU CO2

Emission Performance in State Plans 

TSD. 

We are seeking comment on the 

considerations discussed in this TSD, 

including options presented for how 

projections might be conducted in an 

approvable state plan, and how different 

types of state plan approaches are 

represented in these projections. We are 

seeking further comment on whether the 

EPA should develop guidance that 

describes acceptable projection 

approaches, tools, and methods for use 

in an approvable plan, as well as 

providing technical resources for 

conducting projections. 

The ISO/RTO Council, an 

organization of electric grid operators, 

has suggested that ISOs and RTOs could 

provide analytic support to help states 

develop and implement their plans. The 

ISOs and RTOs have the capability to 

model the system-wide effects of 

individual state plans. Providing 

assistance in this way, they felt, would 

allow states with borders that fall within 

an ISO or RTO footprint to assess the 

system-wide impacts of potential state 

plan approaches. In addition, as the 

state implements its plan, ISO/RTO 

analytic support would allow the state 

to monitor the effects of its plan on the 

regional electricity system. ISO/RTO 

analytic capability could help states 

assure that their plans are consistent 

with region-wide system reliability. The 

ISO/RTO Council suggested that the 

EPA ask states to consult with the 

applicable ISO/RTO in developing their 

state plans. The EPA agrees with this 

suggestion and encourages states with 

borders that fall within one or more ISO 

or RTO footprints to consult with the 

relevant ISOs/RTOs. 

8. Potential Emission Reduction 

Measures Not Used To Set Proposed 

Goals 

States may include measures in their 

plans beyond those that the EPA 

included in its determination of the 

BSER. In general, any measures that 

meet the proposed criteria for 

approvable state plans could be 

employed in a state plan. Beyond that, 

under a mass-based approach, any 

measure that reduces affected EGU 

emissions—even if not included in the 

state plan—will, if implemented during 

a plan performance period, help to 

achieve actual emissions performance 

that meets the required level. 

Beyond the types of state plan 

measures already discussed in this 

section of the preamble, the agency has 

identified a number of other measures 

that could also lead to CO2 emission 

reductions from EGUs. These include, 

for example, electricity transmission 

and distribution efficiency 

improvements, retrofitting affected 

EGUs with partial CCS, the use of 

biomass-derived fuels at affected EGUs, 

and use of new NGCC units. Although 

the emission reduction methods 

discussed in this section are not 

proposed to be part of the BSER, the 

agency anticipates that some states may 

be interested in using these approaches 

in their state plans. The agency solicits 

comment on whether these measures are 

appropriate to include in a state plan to 

achieve CO2 emission reductions from 

affected EGUs. In addition to the 

specific requests for comment related to 

specific technologies below, we also 

request comment on other measures that 

would be appropriate. In addition, we 

request comment on whether the EPA 

should provide specific guidance on 

inclusion of these measures in a state 

plan. 

In addition, technological advances 

and innovations in energy and pollution 

control technologies will continue over 

time. The agency is aware that as new 

technologies become available or as 

costs of a technology drop because of 

technical advances, states may wish to 

include measures in their state plans 

that make use of those technologies. 

To be more specific, there are 

multiple potential measures that can be 

taken at an EGU beyond heat rate 

improvements that will reduce CO2

emissions. Some examples are: 

Including co-firing of less CO2 intensive 

fuels such as natural gas, retrofit of 

partial CCS and use of integrated 

renewable technology (i.e. meeting some 

of the steam load in a steam turbine 

from a fossil unit and part of the steam 

load from a concentrating solar 

installation), and improving heat rates 

of oil- and gas-fired generating units. 

Co-firing of natural gas and the use of 

CCS could be incorporated into a state 

plan demonstration of emission 

performance as a reduction in the 

emission rate at an affected EGU in 

exactly the same way that heat rate 

reductions could be quantified. In the 

case of an integrated renewable and 

fossil unit, reductions could either be 

quantified as a reduction in rate, or the 

renewable component could be 

quantified in the same way other 

renewable reductions are quantified in 

the state plan. 

In addition to the nuclear generation 

taken into account in the state goals 

analysis, any additional new nuclear 

generating units or uprating of existing 

nuclear units, relative to a baseline of 

capacity as of the date of proposal of the 

emission guidelines, could be a 

component of state plans. This baseline 

would be consistent with the proposed 

approach for treatment of existing state 

programs. The agency requests comment 

on alternative nuclear capacity 

baselines, including whether the date 

for recognizing additional non-BSER 

nuclear capacity should be the end of 

the base year used in the BSER analysis 

of potential nuclear capacity (i.e., 2012). 

In general, when considering nuclear 

generation in a state plan, states may 

wish to consider the impacts that 

different types of policies may have on 

different types of zero-emitting 

generation. Under a capped approach 

which does not provide any ‘‘crediting’’ 

for zero-emitting generation, the impact 

on all zero-emitting units should be the 

same. In a rate based approach that 

credited zero or low-emitting 

generation, the crediting mechanism 

used could result in different economic 

impacts on different types of zero- or 

low-emitting generation. 

Another way that a state plan could 

reduce utilization and emissions from 

affected existing EGUs would be 

through construction of new NGCC— 

that is, NGCC on which construction 

commences after the date of proposal or 

finalization of CAA section 111(b) 

standards applicable to that source. (The 

agency’s CAA section 111(d) proposal 

does not include new NGCC as a 

component of the BSER, but requests 

comment on that question in Section VI 

of this preamble.) Under a mass-based 

plan where an emission limit on 

affected EGUs would assure 

achievement of the required level of 

emission performance in the state plan, 

any emission reductions at affected 

EGUs resulting from substitution of new 

NGCC generation for higher-emitting 

generation by existing affected EGUs 

would automatically be reflected in 

mass emission reductions from affected 

EGUs. A state would not need to 

include enforceable provisions for new 

NGCC in its plan, under such an 

approach. However, under a mass-based 

portfolio approach, enforceable 

measures in a state plan might include 


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construction of new NGCC to replace 

one or more affected EGUs, perhaps as 

part of a utility IRP and related PUC 

orders. Again, the effects of new NGCC 

generation would be realized in reduced 

mass emissions from affected EGUs. 

The agency requests comment on how 

emissions changes under a rate-based 

plan resulting from substitution of 

generation by new NGCC for generation 

by affected EGUs should be calculated 

toward a required emission performance 

level for affected EGUs. Specifically, 

considering the legal structure of CAA 

section 111(d), should the calculation 

consider only the emission reductions at 

affected EGUs, or should the calculation 

also consider the new emissions added 

by the new NGCC unit, which is not an 

affected unit under section 111(d)? 

Should the emissions from a new NGCC 

included as an enforceable measure in 

a mass-based state plan (e.g., in a plan 

using a portfolio approach) also be 

considered? 

Similar to zero-emitting generation, 

states may also want to consider 

whether the policy design they choose 

sends similar or different price signals 

to new and existing NGCC. For instance, 

under a mass based program, if new 

NGCCs were not included, their costs 

would be less than the cost of an 

existing NGCC unit. 

In respect to new fossil fuel-fired 

EGUs, the agency also requests 

comment on the concept of providing 

credit toward a state’s required CAA 

section 111(d) performance level for 

emission performance at new CAA 

section 111(b) affected units that, 

through application of CCS, is superior 

to the proposed standards of 

performance for new EGUs. Because the 

EPA proposed to find that the BSER for 

new fossil fuel-fired boilers and IGCC 

units is only a partial application of 

CCS, we recognize that there is the 

potential for such units, if constructed, 

to obtain additional emission reductions 

by increasing the level of CCS and 

outperforming the proposed 

performance standards. In some cases 

these incremental emission reductions 

may represent a cost effective abatement 

option for states and would provide an 

incentive for the deployment and 

advancement of CCS. We invite 

comment on whether incremental 

emission reductions from new fossil 

fuel-fired boilers and IGCC units with 

CCS, based on exceeding the CAA 

section 111(b) performance standards 

for such units, should be allowed as a 

compliance option to help meet the 

emission performance level required 

under a CAA section 111(d) state plan. 

Similarly, while the EPA did not 

propose to establish standards of 

performance for new NGCC units based 

on CCS under CAA section 111(b), we 

recognize that if a new NGCC unit were 

to be constructed with a CCS system, it 

could achieve a lower CO2 emission rate 

than required by the proposed standards 

of performance for new NGCC units. We 

invite comment on whether incremental 

emission reductions from new NGCC 

units that outperform the performance 

standards for such units under CAA 

section 111(b) based on the use of CCS 

should be allowed as a compliance 

option to help meet the emission 

performance level required under a 

CAA section 111(d) state plan. 

Building block 4 focuses on 

improving end-use energy efficiency. 

Another way to reduce the utilization 

of, and CO2 emissions from, affected 

EGUs is through electricity transmission 

and distribution upgrades that reduce 

electricity losses during the delivery of 

electricity to end users. Just as end-use 

energy efficiency can reduce mass 

emissions from affected EGUs, so can 

transmission upgrades. 

In addition, electricity storage 

technologies have the potential to 

enhance emission performance by 

reducing the need for fossil fuel-fired 

EGUs to provide generation during 

periods when intermittent wind and 

solar generation are unavailable due to 

natural conditions. States may wish to 

consider this possibility as they 

consider options for design of their 

plans. 

The agency requests comment on 

whether industrial combined heat and 

power approaches warrant 

consideration as a potential way to 

avoid affected EGU emissions, and 

whether the answer depends on 

circumstances that depend on the type 

of CHP in question. 

Many of the decisions that states will 

make while developing compliance 

approaches are fundamentally state 

decisions that will have impacts on 

issues important to the state, including 

cost to consumers and broader energy 

policy goals, but will not impact overall 

emission performance. Some decisions, 

however, may impact emission 

performance and exemplify the kinds of 

decisions and approaches states may be 

interested in pursuing. In light of the 

broad latitude that the EPA is seeking to 

afford the states, including latitude to 

adopt measures such as those discussed 

in this subsection, the EPA intends to 

make additional technical resources 

available and consider developing 

guidance for states, should they need 

such support in exploring and adopting 

these options. The EPA, in addition, 

requests comment on whether there are 

still other areas beyond those discussed 

above for which it would be useful for 

the EPA to provide guidance. 

Through President Obama’s Climate 

Action Plan, the Administration is 

working to identify new approaches to 

protect and restore our forests, as well 

as other critical landscapes including 

grasslands and wetlands, in the face of 

a changing climate. Sustainable forestry 

and agriculture can improve resiliency 

to climate change, be part of a national 

strategy to reduce dependence on fossil 

fuels, and contribute to climate change 

mitigation by acting as a ‘‘sink’’ for 

carbon. The plant growth associated 

with producing many of the biomassderived fuels can, to varying degrees for 

different biomass feedstocks, sequester 

carbon from the atmosphere. For 

example, America’s forests currently 

play a critical role in addressing carbon 

pollution, removing nearly 12 percent of 

total U.S. greenhouse gas emissions 

each year. As a result, broadly speaking, 

burning biomass-derived fuels for 

energy recovery can yield climate 

benefits as compared to burning 

conventional fossil fuels. 

Many states have recognized the 

importance of forests and other lands for 

climate resilience and mitigation and 

have developed a variety of different 

sustainable forestry policies, renewable 

energy incentives and standards and 

greenhouse gas accounting procedures. 

Because of the positive attributes of 

certain biomass-derived fuels, the EPA 

also recognizes that biomass-derived 

fuels can play an important role in CO2

emission reduction strategies. We 

anticipate that states likely will consider 

biomass-derived fuels in energy 

production as a way to mitigate the CO2

emissions attributed to the energy sector 

and include them as part of their plans 

to meet the emission reduction 

requirements of this rule, and we think 

it is important to define a clear path for 

states to do so. 

To better understand the impacts of 

using different types of biomass-derived 

fuels, the EPA is assessing the use of 

biomass feedstocks for energy recovery 

by stationary sources and has developed 

a draft accounting framework that the 

EPA’s Science Advisory Board (SAB) 

has reviewed. The draft framework 

concluded that while biomass and other 

biogenic feedstocks have the potential to 

reduce the overall level of CO2

emissions resulting from electricity 

generation, the contribution of biomassderived fuels to atmospheric CO2 is 

sensitive to the type of biomass 

feedstock used, and the way in which 

the feedstock is grown, processed, and 

ultimately combusted as a fuel for 

energy production. The SAB in its 

review similarly found that there are 


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302The agency is not reopening or considering 

changes to this provision of the implementing 

regulations. 303 40 CFR 60.24(f). 

304See ‘‘Phosphate Fertilizer Plants; Final 

Guideline Document Availability,’’ 42 FR 12,022 

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

Stationary Sources; Emission Guideline for Sulfuric 

Acid Mist,’’ 42 FR 55,796 (Oct. 18, 1977); ‘‘Kraft 

Pulp Mills, Notice of Availability of Final Guideline 

Document,’’ 44 FR 29,828 (May 22, 1979); ‘‘Primary 

Aluminum Plants; Availability of Final Guideline 

Document,’’ 45 FR 26,294 (Apr. 17, 1980); 

‘‘Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, Final 

Rule,’’ 61 FR 9905 (Mar. 12, 1996). 

circumstances in which biomass is 

grown, harvested and combusted in a 

carbon neutral fashion but commented 

that additional considerations are 

warranted. 

The EPA is in the process of revising 

the draft framework and considering 

next steps, taking into account both the 

comments provided by the SAB and 

feedback from stakeholders. The EPA’s 

biogenic CO2 accounting framework is 

expected to provide important 

information regarding the scientific 

basis for assessing these biomassderived fuels and their net atmospheric 

contribution of CO2 related to the 

growth, harvest and use of these fuels. 

This information should assist both 

states and the EPA in assessing the 

impact of the use of biomass fuels in 

reaching emission reduction goals in the 

energy sector under state plans to 

comply with the requirements in the 

emission guidelines. 

9. Consideration of a Facility’s 

‘‘Remaining Useful Life’’ in Applying 

Standards of Performance 

In this section, the EPA discusses the 

relevance to this rule of the EPA 

regulations implementing the CAA 

section 111(d)(1) provision ‘‘permit[ing] 

the State in applying a standard of 

performance to any particular source 

under a [111(d)] plan . . . to take into 

consideration, among other factors, the 

remaining useful life of the existing 

source to which such standard applies.’’ 

For the reasons discussed below, the 

EPA is proposing that, in this case, the 

flexibility provided in the state plan 

development process adequately allows 

for consideration of the remaining 

useful life of the affected facilities and 

other source-specific factors and, 

therefore, that separate application of 

the remaining useful life provision by 

states in the course of developing and 

implementing their CAA section 111(d) 

plans is unnecessary. The agency is 

requesting comment on its analysis 

below of the implications of the EPA’s 

existing regulations interpreting ‘‘useful 

life’’ and ‘‘other factors’’ for purposes of 

this rulemaking.302 The agency also 

requests comment on whether it would 

be desirable to include in regulatory text 

any aspects of this preamble discussion 

about how the provisions in the existing 

implementing regulations concerning 

source-specific factors relate to this 

emission guideline. 

This section addresses the legal 

background concerning facility-specific 

considerations and the implications for 

implementation of these emission 

guidelines, including state emissions 

performance goals. 

a. Legal Background 

The EPA’s 1975 implementing 

regulations 303 address remaining useful 

life and other facility-specific factors 

that might affect requirements for an 

existing source under section 111(d). 

Those regulations provide that for a 

pollutant such as GHGs, which have 

been found to endanger public health, 

standards of performance in state plans 

must be as stringent as the EPA’s 

emission guidelines. Deviation from the 

standard might be appropriate where 

the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control 

resulting from plant age, location, or 

basic process design; 

(2) Physical impossibility of installing 

necessary control equipment; or 

(3) Other factors specific to the facility 

(or class of facilities) that make 

application of a less stringent standard 

or final compliance time significantly 

more reasonable. 

The reference to ‘‘[u]nreasonable cost 

of control resulting from plant age’’ 

implements the statutory provision on 

remaining useful life. The language 

concerning plant location, basic process 

design, physical impossibility of 

installing controls, and ‘‘other factors’’ 

addresses facility-specific issues other 

than remaining useful life that the EPA 

determined that in some circumstances 

can affect the reasonableness of a 

control measure for a particular existing 

source. 

This regulatory provision provides the 

EPA’s default structure for 

implementing the remaining useful life 

provision of CAA section 111(d). The 

opening clause, however, which 

provides that this provision is 

applicable ‘‘unless otherwise specified 

in the applicable subpart’’ makes clear 

that this structure may not be 

appropriate in each case and that the 

EPA has discretion to alter the extent to 

which states may authorize relaxations 

to standards of performance that would 

otherwise apply to a particular source or 

source category, if appropriate under the 

circumstances of the specific source 

category and proposed guidelines. 

b. Implications for Implementation of 

These Emission Guidelines 

In general, the EPA notes that the 

implementing regulation provisions for 

remaining useful life and other facilityspecific factors are relevant for emission 

guidelines in which the EPA specifies a 

presumptive standard of performance 

that must be fully and directly 

implemented by each individual 

existing source within a specified 

source category. Such guidelines are 

much more like a CAA section 111(b) 

standard in their form. For example, the 

EPA emission guidelines for sulfuric 

acid plants, phosphate fertilizer plants, 

primary aluminum plants, and Kraft 

pulp plants specify emission limits for 

sources.304 In the case of such emission 

guidelines, some individual sources, by 

virtue of their age or other unique 

circumstances, may warrant special 

accommodation. 

In these proposed guidelines for state 

plans to limit CO2 from affected EGUs, 

the agency does not take that approach. 

Instead, the EPA is proposing to 

establish state emission performance 

goals for the collective group of affected 

EGUs in a state, leaving to each state the 

design of the specific requirements that 

fall on each affected EGU. Due to the 

inherent flexibility in the EPA’s 

approach to establishing the statespecific goals, and the flexibility 

provided to states in developing 

approvable CAA section 111(d) plans to 

achieve those goals, the EPA’s 

guidelines contain no emission 

standards that the state must apply 

directly to a specific EGU; therefore, no 

relief for individual facilities would be 

needed. 

Rather, because of the flexibility for 

states to design their own standards, the 

states have the ability to address the 

issues involved with ‘‘remaining useful 

life’’ and ‘‘other factors’’ in the initial 

design of those standards, which would 

occur within the framework of the CAA 

section 111(d) plan development 

process. States are free to specify 

requirements for individual EGUs that 

are appropriate considering remaining 

useful life and other facility-specific 

factors. 

Therefore, to the extent that a 

performance standard that a state may 

wish to adopt for affected EGUs raises 

facility-specific issues, the state is free 

to make adjustments to a particular 

facility’s requirements on facilityspecific grounds, so long as any such 

adjustments are reflected (along with 


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305The agency requests comment on whether 

there are circumstances other than a major capital 

investment that could lead to a prospective state 

plan imposing unreasonable costs considering a 

facility’s remaining useful life. Where annual costs 

predominate and/or capital costs do not constitute 

a major expense, the EPA believes that the 

remaining useful life of an affected EGU will not 

significantly affect its annualized cost of control 

and therefore should not be a factor in determining 

control requirements for the EGU. 

306Heat rate improvement methods and related 

capital costs are discussed in the GHG Abatement 

Measures TSD; SO2 scrubber capital costs are from 

the documentation for the EPA’s IPM Base Case 

v5.13, Chapter 5, Table 5–3, available at http://

www.epa.gov/powersectormodeling/

BaseCasev513.html 

307CAA section 111(h)(4). 

308CAA section 111(h)(5). 

any necessary compensating emission 

reductions), as part of the state’s CAA 

section 111(d) plan submission. The 

agency requests comment on its 

interpretation. 

c. Relationship to State Emission 

Performance Goals and Timing of 

Achievement 

The EPA also believes that, because of 

the way the state-specific goals have 

been developed in these proposed 

guidelines, remaining useful life and 

other facility-specific considerations 

should not affect the determination of a 

state’s rate-based or mass-based 

emission performance goal or the state’s 

obligation to develop and submit an 

approvable CAA section 111(d) plan 

that achieves that goal by the applicable 

deadline. 

Under the proposed guideline, states 

would have the flexibility to adopt a 

state plan that relies on emissionreducing requirements that do not 

require affected EGUs with a short 

remaining useful life to make major 

capital expenditures 305 or incur 

unreasonable costs. Indeed, the EPA’s 

proposal would provide states with 

broad flexibility regarding ways to 

improve emission performance through 

utilizing the emissions reduction 

methods represented by the four 

‘‘building blocks.’’ 

We also note that a state is not 

required to achieve the same level of 

emission reductions with respect to any 

one building block as assumed in the 

EPA’s BSER analysis. If a state prefers 

not to attempt to achieve the level of 

performance estimated by the EPA for a 

particular building block, it can 

compensate through over-achievement 

in another one, or employ other 

compliance approaches not factored 

into the state-specific goal at all. The 

EPA has estimated reasonable rather 

than maximum possible implementation 

levels for each building block in order 

to establish overall state goals that are 

achievable/while allowing states to take 

advantage of the flexibility to pursue 

some building blocks more aggressively, 

and others less aggressively, than is 

reflected in the goal computations, 

according to each state’s needs and 

preferences. 

Of the four building blocks 

considered by the EPA in developing 

state goals, only the first block, heat rate 

improvements, involves capital 

investments at the affected EGUs which, 

if mandated by a state rule, might give 

rise to remaining useful life 

considerations at a particular facility. 

The other building blocks—re-dispatch 

among affected sources, addition of new 

generating capacity, and improvement 

in end-use energy efficiency—do not 

generally involve capital investments by 

the owner/operator at an affected EGU. 

In the case of heat rate improvements 

at affected EGUs, states can choose 

whether to require a greater or lesser 

degree of heat rate improvement than 

the 6 percent improvement assumed in 

the EPA’s proposed BSER 

determination, either because of the 

remaining useful life of one or more 

EGUs, other source-specific factors that 

the state deemed appropriate to 

consider, or any other relevant reasons. 

The agency also notes that any capital 

expenditures would be much smaller 

than capital expenditures required for 

example, for purchase and installation 

of scrubbers to remove sulfur dioxide; a 

fleet-wide average cost for heat rate 

improvements at coal-fired generating 

units is $100/kW, compared with a 

typical SO2 scrubber cost of $500/kw 

(costs vary with unit size).306 In 

addition, the proposed guideline allows 

states to regulate affected EGUs through 

flexible regulatory approaches that do 

not require affected EGUs to incur large 

capital costs (e.g., averaging and trading 

programs). Under the EPA’s proposed 

approach—establishing state goals and 

providing states with flexibility in plan 

design—states have flexibility to make 

exactly the kind of judgments necessary 

to avoid requirements that would result 

in stranded assets. 

Remaining useful life and other 

factors, because of their facility-specific 

nature, are potentially relevant in 

determining requirements that are 

directly applicable to affected EGUs. For 

all of the reasons above, the agency 

believes that the issue of remaining 

useful life will arise infrequently in the 

development of state plans to limit CO2

emissions from affected existing EGUs. 

Even if relief is due a particular facility, 

the state has an available toolbox of 

emission reduction methods that it can 

use to develop a section 111(d) plan that 

meets its emissions performance goal on 

time. The EPA therefore proposes that 

the remaining useful life of affected 

EGUs, and the other facility-specific 

factors identified in the existing 

implementing regulations, should not be 

considered as a basis for adjusting a 

state emission performance goal or for 

relieving a state of its obligation to 

develop and submit an approvable plan 

that achieves that goal on time. The 

agency solicits comment on this 

position. 

10. Design, Equipment, Work Practice, 

or Operational standards 

In this section, we discuss whether 

state plans may include design, 

equipment, work practice, or 

operational standards. 

CAA section 111(h)(1) authorizes the 

Administrator to promulgate ‘‘a design, 

equipment, work practice, or 

operational standard, or combination 

thereof,’’ if in his or her judgment, ‘‘it 

is not feasible to prescribe or enforce a 

standard of performance.’’ CAA section 

111(h)(2) provides the circumstances 

under which prescribing or enforcing a 

standard of performance is ‘‘not 

feasible’’: generally, when the pollutant 

cannot be emitted through a conveyance 

designed to emit or capture the 

pollutant, or when there is no 

practicable measurement methodology 

for the particular class of sources. Other 

provisions in section 111(h) further 

provide that a design, equipment, work 

practice, or operational standard (i) 

must ‘‘be promulgated in the form of a 

standard of performance whenever it 

becomes feasible’’ to do so,307 and (ii) 

must ‘‘be treated as a standard of 

performance’’ for purposes of, in 

general, the CAA.308

As noted above, CAA section 111(d) 

requires that state plans ‘‘establish[] 

standards of performance’’ as well as 

‘‘provide[] for the implementation and 

enforcement of such standards of 

performance.’’ CAA section 111(d) is 

silent as to whether (i) states may 

include design, equipment, work 

practice, or operational standards, or (ii) 

they may include those types of 

standards, but only under the limited 

circumstances described in section 

111(h) (i.e., when it is ‘‘not feasible’’ to 

prescribe or enforce a standard of 

performance). Similarly, section 111(h) 

applies by its terms when the 

Administrator is authorized to prescribe 

standards of performance (which would 

include rulemaking under CAA section 

111(b)), but is silent as to whether it 


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309 It should be noted that section 111(b)(5), 

which concerns controls promulgated by the 

Administrator for new and modified sources, does 

refer to section 111(h). 

310Typically, in a mass emission limit trading 

program, sources are required to obtain an 

allowance for each measure (e.g., ton) of air 

pollutant they emit. The acid rain program under 

Title IV of the CAA is an example of this type of 

trading program. 

311Engine Mfrs. Ass’n v. South Coast Air Quality 

Mgmt. Dist., 541 U.S. 246, 252–53 (2004) (quoting 

Webster’s Second International Dictionary, at 2455 

(1945)) 

312See ‘‘Standards of Performance for New and 

Existing Stationary Sources: Electric Utility Steam 

Generating Units, Final Rule,’’ 70 FR 28,606 (May 

18, 2005) [also known as the Clean Air Mercury 

Rule, or ‘‘CAMR’’], vacated on other grounds by 

New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008), 

cert denied sub nom. Util. Air Reg. Grp. v. New 

Jersey, 555 U.S. 1169 (2009); ‘‘Standards of 

Performance for New Stationary Sources and 

Emission Guidelines for Existing Sources; 

Municipal Waste Combustors,’’ 60 FR 65,387 (Dec. 

19, 1995) (trading rules codified in 40 CFR 

60.33b(d)(1)–(2)). 

applies to state plans under CAA 

section 111(d).309

We invite consideration of the proper 

interpretation of CAA sections 111(d) 

and (h), under either Chevron step 1 or 

step 2, specifically: (i) Do the provisions 

of section 111(d) preclude state plans 

from including ‘‘design, equipment, 

work practice, or operational 

standard[s]’’ unless those things can be 

considered ‘‘standards of performance’’ 

or as providing for the implementation 

and enforcement of such standards? As 

a related matter, do the references to 

‘‘standard[s] of performance’’ in CAA 

section 111(h) indicate that design, 

equipment, work practice, or 

operational standards cannot be 

considered ‘‘standards of performance?’’ 

(ii) Alternatively, are state plans 

authorized to include those design, 

equipment, work practice, or 

operational standards, but only under 

the limited circumstances described in 

CAA section 111(h) relating to 

infeasibility? (iii) As another alternative, 

are state plans authorized to include 

design, equipment, work practice, or 

operational standards under all 

circumstances, so that the limits of CAA 

section 111(h) do not apply? Finally, to 

the extent there is legal uncertainty over 

whether, and under what 

circumstances, state plans may include 

those standards, should the EPA 

authorize state plans to include them, 

on the understanding that if the Court 

invalidates the EPA’s interpretation, 

states would be required to revise their 

plans accordingly without further 

rulemaking from the EPA? 

11. Emissions Averaging and Trading 

In this section, we discuss why CAA 

section 111(d) plans may include 

standards of performance that authorize 

emissions averaging and trading. 

CAA section 111(d) authorizes state 

plans to include ‘‘standards of 

performance’’ and measures that 

implement and enforce those standards 

of performance. CAA section 111(a)(1) 

defines a ‘‘standard of performance’’ as 

‘‘a standard for emissions of air 

pollutants which reflects the degree of 

emission limitation achievable through 

the application of the best system of 

emission reduction . . . adequately 

demonstrated.’’ CAA section 302 

contains a set of definitions that apply 

‘‘[w]hen used in [the Clean Air Act],’’ 

including subsection (l), which provides 

a separate definition of ‘‘standard of 

performance’’ as ‘‘a requirement of 

continuous emission reduction. . .’’ 

The EPA proposes that the definition 

of ‘‘standard of performance’’ is broad 

enough to incorporate emissions 

averaging and trading provisions, 

including both emission rate programs, 

in which sources may average or trade 

those rates, and mass emission limit 

programs, in which sources may buy 

and sell mass emission allowances (and, 

under certain circumstances, offsets).310

The term ‘‘standard’’ in the phrase 

‘‘standard for emissions of air 

pollutants’’ is not defined in the CAA. 

As the Supreme Court noted in a CAA 

case, a ‘‘standard’’ is simply ‘‘that which 

‘is established by authority, custom, or 

general consent, as a model or example; 

criterion; test.’ ’’ 311 A tradable emission 

rate or a tradable mass limit is a 

‘‘standard for emissions of air 

pollutants’’ because it establishes an 

emissions limit for a source’s air 

pollutants, and as a result, qualifies as 

a ‘‘criterion’’ or ‘‘test’’ for those air 

pollutants. 

Moreover, although there may be 

doubt that the definition of ‘‘standard of 

performance’’ in CAA section 302(l) 

applies to CAA section 111(d) in light 

of the fact that the definition of the same 

term in CAA section 111(a)(1) is more 

specific, even if the CAA section 302(l) 

definition does apply, an averaging or 

trading requirement qualifies as a 

‘‘continuous emission reduction’’ 

because, in the case of a tradable 

emission rate, the rate is applicable at 

all times, and, in the case of a tradable 

mass limit, the source is always under 

the obligation that its emissions be 

covered by allowances. 

It should be noted that the EPA has 

promulgated two other CAA section 

111(d) rulemakings that authorized state 

plans to include emissions averaging or 

trading.312

G. Additional Factors That Can Help 

State Meet Their CO2 Emission 

Performance Goals 

A resource available from the EPA for 

states pursuing market-based 

approaches is the EPA’s data and 

experience in support of state trading 

programs and emissions data collection. 

For states needing technical assistance 

with data or operation of market-based 

programs, existing EPA data systems are 

a resource that have been used to collect 

emissions data, track allowances and 

transfers, and determine compliance for 

state programs. For example, New 

Hampshire was part of the Ozone 

Transport Commission (OTC) trading 

program but was not included in the 

NOx SIP Call. Because the state wanted 

its sources to continue to participate in 

a state trading program, the EPA 

operated the emissions trading program 

for New Hampshire sources, from 

allocating allowances to compliance 

determination. 

Additionally, as noted elsewhere in 

this preamble, more than 25 states have 

mandatory renewable portfolio 

standards, and other states have 

voluntary renewable programs and 

goals. There is considerable diversity 

among the states in the scope and 

coverage of these standards, in 

particular in how renewable resources 

are defined. At the federal level, the 

EPA has considered the greenhouse gas 

implications related to biomass use at 

stationary sources through several 

actions, including a call for information 

from stakeholders and the development 

and review of the ‘‘Accounting 

Framework for Biogenic CO2 Emissions 

from Stationary Sources,’’ issued in 

September 2011. That study was 

reviewed by the EPA’s Science Advisory 

Board in 2011 and 2012 and the agency 

continues to assess the framework and 

consider the latest scientific analyses 

and technical input received from 

stakeholders. The EPA expects that the 

framework, when finalized, will be a 

resource that could help inform states in 

the development of their CAA section 

111(d) plans. 

H. Resources for States To Consider in 

Developing Their Plans 

As part of the stakeholder outreach 

process, the EPA asked states what the 

agency could do to facilitate state plan 

development and implementation. 

Some states indicated that they wanted 

the EPA to create resources to assist 

with state plan development, especially 

resources related to accounting for enduse energy efficiency and renewable 

energy (EE/RE) in state plans. They 

requested clear methodologies for 


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313http://epa.gov/airquality/eere/. 

314http://www1.eere.energy.gov/seeaction/

index.html. 

315Appendix, State Plan Considerations TSD. 

316http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html. 

317Certain stationary sources that emit or have 

the potential to emit a pollutant at a level that is 

equal to or greater than specified thresholds are 

subject to major source requirements. See, e.g., CAA 

§§ 165(a)(1), 169(1), 501(2), 502(a). A synthetic 

minor limitation is a legally and practicably 

enforceable restriction that has the effect of limiting 

emissions below the relevant level and that a source 

voluntarily obtains to avoid major stationary source 

requirements, such as the PSD or title V permitting 

programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 

70.2 (definition of ‘‘potential to emit’’). 

measuring EE/RE policies and programs, 

so that these could be included as part 

of their compliance strategies. 

Stakeholders said that these tools and 

metrics should build upon the EPA’s 

‘‘Roadmap for Incorporating Energy 

Efficiency/Renewable Energy Policies 

and Programs into State and Tribal 

Implementation Plans,’’313 as well as the 

State Energy Efficiency Action 

Network’s ‘‘Energy Efficiency Program 

Impact Evaluation Guide.’’314 The EPA 

also heard that states would like 

examples of effective state policies and 

programs. 

As a result of this feedback, in 

consultation with U.S. Department of 

Energy and other federal agencies, the 

EPA has developed a toolbox of 

decision support resources and is 

making that available at a dedicated 

Web site: http://www2.epa.gov/ 

www2.epa.gov/cleanpowerplantoolbox. 

Current resources on the site focus on 

approaches states and other entities 

have already taken that reduce CO2

emissions from the electric utility 

sector. 

For the final rulemaking, the EPA 

plans to organize resources on the Web 

site around the following two categories: 

State plan guidance and state plan 

decision support. The state plan 

guidance section will serve as a central 

repository for the final emission 

guidelines, regulatory impact analysis, 

technical support documents, and other 

supporting materials. The state plan 

decision support section will include 

information to help states evaluate 

different approaches and measures they 

might consider as they initiate plan 

development. This section will include, 

for example, a summary of existing state 

climate and EE/RE policies and 

programs,315 National Action Plan for 

Energy Efficiency (Action Plan),316

information on electric utility actions 

that reduce CO2, and tools and 

information to assist with translating 

energy savings into emission reductions. 

We note that our inclusion of a 

measure in the toolbox does not mean 

that a state plan must include that 

measure. In fact, inclusion of measures 

provided at the Web site does not 

necessarily imply the approvability of 

an approach or method for use in a state 

plan. States will need to demonstrate 

that any measure included in a state 

plan meets all relevant approvability 

criteria and adequately addresses 

elements of the plan components 

discussed in Section VIII of this 

preamble. 

The EPA solicits comment on this 

approach and the information currently 

included, and planned for inclusion, in 

the Decision Support Toolbox. 

IX. Implications for Other EPA 

Programs and Rules 

A. Implications for New Source Review 

Program 

The new source review (NSR) 

program is a preconstruction permitting 

program that requires major stationary 

sources of air pollution to obtain 

permits prior to beginning construction. 

The requirements of the NSR program 

apply both to new construction and to 

modifications of existing major sources. 

Generally, a source triggers these 

permitting requirements as a result of a 

modification when it undertakes a 

physical or operational change that 

results in a significant emission increase 

and a net emissions increase. NSR 

regulations define what constitutes a 

significant net emissions increase, and 

the concept is pollutant-specific. For 

GHG emissions, the PSD applicability 

analysis is described in the Prevention 

of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule (FR 75 

31514, June 3, 2010). As a general 

matter, a modifying major stationary 

source would trigger PSD permitting 

requirements for GHGs if it emits GHGs 

in excess of 100,000 tons per year (tpy) 

of carbon dioxide equivalents (CO2e), 

and it undergoes a change or change in 

the method of operation (modification) 

resulting in an emissions increase of 

75,000 tpy CO2e as well as an increase 

on a mass basis. Once it has been 

determined that a change triggers the 

requirements of the NSR program, the 

source must obtain a permit prior to 

making the change. The pollutant(s) at 

issue and the air quality designation of 

the area where the facility is located or 

proposed to be built determine the 

specific permitting requirements. 

As part of its CAA section 111(d) 

plan, a state may impose requirements 

that require an affected EGU to 

undertake a physical or operational 

change to improve the unit’s efficiency 

that results in an increase in the unit’s 

dispatch and an increase in the unit’s 

annual emissions. If the emissions 

increase associated with the unit’s 

changes exceeds the thresholds in the 

NSR regulations discussed above for one 

or more regulated NSR pollutants, 

including the netting analysis, the 

changes would trigger NSR. 

While there may be instances in 

which an NSR permit would be 

required, we expect those situations to 

be few. As previously discussed in this 

preamble, states have considerable 

flexibility in selecting varied measures 

as they develop their plans to meet the 

goals of the emissions guidelines. One 

of these flexibilities is the ability of the 

state to establish the standards of 

performance in their CAA section 

111(d) plans in such a way so that their 

affected sources, in complying with 

those standards, in fact would not have 

emissions increases that trigger NSR. To 

achieve this, the state would need to 

conduct an analysis consistent with the 

NSR regulatory requirements that 

supports its determination that as long 

as affected sources comply with the 

standards of performance in their CAA 

section 111(d) plan, the source’s 

emissions would not increase in a way 

that trigger NSR requirements. 

For example, a state could decide to 

adjust its demand side measures or 

increase reliance on renewable energy 

as a way of reducing the future 

emissions of an affected source initially 

predicted (without such alterations) to 

increase its emissions as a result of a 

CAA section 111(d) plan requirement. 

In other words, a state plan’s 

incorporation of expanded use of 

cleaner generation or demand-side 

measures could yield the result that 

units that would otherwise be projected 

to trigger NSR through a physical 

change that might result in increased 

dispatch would not, in fact, increase 

their emissions, due to reduced demand 

for their operation. The state could also, 

as part of its CAA section 111(d) plan, 

develop conditions for a source 

expected to trigger NSR that would limit 

the unit’s ability to move up in the 

dispatch enough to result in a 

significant net emissions increase that 

would trigger NSR (effectively 

establishing a synthetic minor limit). 317

We request comment on whether, 

with adequate record support, the state 

plan could include a provision, based 

on underlying analysis, stating that an 

affected source that complies with its 

applicable standard would be treated as 

not increasing its emissions, and if so, 

whether such a provision would mean 

that, as a matter of law, the source’s 

actions to comply with its standard 


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318We discuss other rulemakings solely for 

background purposes. The effort to coordinate 

rulemakings is not a defense to a violation of the 

CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming 

regulations. 

319The pre-publication version of the final rule is 

available at: http://water.epa.gov/lawsregs/

lawsguidance/cwa/316b/#final. 

320CWA section 316(b) provides that standards 

applicable to point sources under sections 301 and 

306 of the Act must require that the location, 

design, construction and capacity of cooling water 

intake structures reflect the best technology 

available for minimizing adverse environmental 

impacts. 

would not subject the source to NSR. 

We also seek comment on the level of 

analysis that would be required to 

support a state’s determination that 

sources will not trigger NSR when 

complying with the standards of 

performance included in the state’s 

CAA section 111(d) plan and the type of 

plan requirements, if any, that would 

need to be included in the state’s plan. 

As a result of such flexibility and 

anticipated state involvement, we 

expect that a limited number of affected 

sources would trigger NSR when states 

implement their plans. 

B. Implications for Title V Program 

The preamble to the re-proposed EGU 

NSPS (70 FR 1429–1519; January 8, 

2014) explained that regulating GHGs 

for the first time under section 111 of 

the CAA would make GHGs ‘‘regulated 

air pollutants’’ for the first time under 

the operating permit regulations of 40 

CFR parts 70 and 71. This would result 

in GHGs becoming ‘‘fee pollutants’’ in 

certain state part 70 permit programs 

and in the EPA’s part 71 permit 

program, thus requiring the collection of 

fees for GHG emissions in these 

programs. Where title V fees would be 

required for GHGs, they would typically 

be charged at the same rate ($ per ton 

of pollutant) as all other fee pollutants. 

This would likely result in excessive 

and unnecessary fees being charged to 

subject sources. To avoid this situation, 

we proposed to exempt GHGs from the 

fee rates in effect for other fee 

pollutants, while proposing an 

alternative fee that would be much 

lower than the fee charged to other fee 

pollutants, yet sufficient to cover the 

costs of addressing GHGs in operating 

permits. 

This title V fee issue is a one-time 

occurrence resulting from the 

promulgation of the first CAA section 

111 standard to regulate GHGs (the EGU 

NSPS for new sources) and is not an 

issue for any other subsequent CAA 

section 111 regulations, so there is no 

need to address any title V fee issues in 

this proposal. Thus, we are not revisiting these title V fee issues in this 

proposal, and we are not proposing any 

additional revisions to any title V 

regulations as part of this action. 

The title V regulations require each 

permit to include emission limitations 

and standards, including operational 

requirements and limitations that assure 

compliance with all applicable 

requirements. Requirements resulting 

from this rule that are imposed on 

affected EGUs or any other potentially 

affected entities that have title V 

operating permits are applicable 

requirements under the title V 

regulations and would need to be 

incorporated into the source’s title V 

permit in accordance with the schedule 

established in the title V regulations. 

For example, if the permit has a 

remaining life of three years or more, a 

permit reopening to incorporate the 

newly applicable requirement shall be 

completed no later than 18 months after 

promulgation of the applicable 

requirement. If the permit has a 

remaining life of less than three years, 

the newly applicable requirement must 

be incorporated at permit renewal. 

C. Interactions With Other EPA Rules 

Existing fossil fuel-fired EGUs, such 

as those covered in this proposal, are or 

will be potentially impacted by several 

other recently finalized or proposed 

EPA rules.318 On February 16, 2012, the 

EPA issued the mercury and air toxics 

standards (MATS) rule (77 FR 9304) to 

reduce emissions of toxic air pollutants 

from new and existing coal- and oilfired EGUs. The MATS rule will reduce 

emissions of heavy metals, including 

mercury (Hg), arsenic (As), chromium 

(Cr), and nickel (Ni); and acid gases, 

including hydrochloric acid (HCl) and 

hydrofluoric acid (HF). These toxic air 

pollutants, also known as hazardous air 

pollutants or air toxics, are known or 

suspected of causing damage to the 

nervous system, cancer, and other 

serious health effects. The MATS rule 

will also reduce SO2 and fine particle 

pollution, which will reduce particle 

concentrations in the air and prevent 

thousands of premature deaths and tens 

of thousands of heart attacks, bronchitis 

cases and asthma episodes. 

The EPA is closely monitoring MATS 

compliance and finds that the industry 

is making substantial progress. Plant 

owners are moving proactively to install 

controls that will achieve the MATS 

performance standards. Certain units, 

especially those that operate 

infrequently, may be considered not 

worth investing in given today’s 

electricity market, and those are closing. 

Existing sources subject to the MATS 

rule are given until April 16, 2015 to 

comply with the rule’s requirements. 

The final MATS rule provided a 

foundation on which states and other 

permitting authorities could rely in 

granting an additional, fourth year for 

compliance provided for by the CAA. 

States report that these fourth year 

extensions are being granted. In 

addition, the EPA issued an 

enforcement policy that provides a clear 

pathway for reliability-critical units to 

receive an administrative order that 

includes a compliance schedule of up to 

an additional year, if it is needed to 

ensure electricity reliability. 

On May 19, 2014, the EPA issued a 

final rule under section 316(b) of the 

Clean Water Act (33 U.S.C. 1326(b)) 

(referred to hereinafter as the 316(b) 

rule).319 This rule establishes new 

standards to reduce injury and death of 

fish and other aquatic life caused by 

cooling water intake structures at 

existing power plants and 

manufacturing facilities.320 The 316(b) 

rule subjects existing power plants and 

manufacturing facilities that withdraw 

in excess of 2 million gallons per day 

(MGD) of cooling water, and use at least 

25 percent of that water for cooling 

purposes, to a national standard 

designed to reduce the number of fish 

destroyed through impingement and a 

national standard for establishing 

entrainment reduction requirements. All 

facilities subject to the rule must submit 

information on their operations for use 

by the permit authority in determining 

316(b) permit conditions. Certain plants 

that withdraw very large volumes of 

water will also be required to conduct 

additional studies for use by the permit 

authority in determining the sitespecific entrainment reduction 

measures for such facilities. The rule 

provides significant flexibility for 

compliance with the impingement 

standards and, as a result, is not 

projected to impose a substantial cost 

burden on affected facilities. With 

respect to entrainment, the rule calls 

upon the permitting authority to in 

establishing appropriate entrainment 

reduction measures, taking into account, 

among other factors, compliance costs, 

facility reliability and grid reliability. 

Existing sources subject to the 316(b) 

rule are required to comply with the 

impingement requirements as soon as 

practicable after the entrainment 

requirements are determined. They 

must comply with applicable sitespecific entrainment reduction controls 

based on the schedule of requirements 

established by the permitting authority. 

The EPA is also reviewing public 

comments and working to finalize two 

proposed rules which will also impact 


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321Beneficial use involves the reuse of CCRs in 

a product to replace virgin raw materials that would 

otherwise be obtained through extraction. The EPA 

encourages the beneficial use of CCRs in an 

appropriate and protective manner, because this 

practice can produce environmental, economic, and 

performance benefits. The Agency recently 

evaluated the environmental impacts associated 

with encapsulated beneficial uses of fly ash used as 

a direct substitute for Portland cement in concrete, 

and FGD gypsum used as a replacement for mined 

gypsum in wallboard. The EPA concluded that the 

beneficial use of CCRs in concrete and wallboard 

is appropriate because the environmental releases 

of constituents of potential concern (COPC) during 

use by the consumer are comparable to or lower 

than those from analogous non-CCR products, or are 

at or below relevant regulatory and health-based 

benchmarks for human and ecological receptors. 

See U.S. Environmental Protection Agency, Coal 

Combustion Residual Beneficial Use Evaluation: Fly 

Ash Concrete and FGD Gypsum Wallboard (2014). 

322U.S. EPA. September 2013. Regulatory Impact 

Analysis for the Proposed Standards of Performance 

for Greenhouse Gas Emissions for New Stationary 

Sources: Electric Utility Generating Units. EPA– 

452/R–13–003. Available at http://www2.epa.gov/ 

sites/production/files/2013–09/documents/

20130920proposalria.pdf. 

323 It should be noted that regulatory obligations 

imposed upon states and sources operate 

independently under different statutes and sections 

of statutes; the EPA expects that states and sources 

will take advantage of available flexibilities as 

appropriate, but will comply with all relevant legal 

requirements. 

324See: Federal Register Vol. 78, No. 110; June 

7, 2013. Page 34441. 

325 In considering how to coordinate the potential 

requirements between the SE ELG and CCR rules, 

the EPA stated that it is guided by the following 

policy considerations: First and foremost, the EPA 

intends to ensure that its statutory responsibilities 

to restore and maintain water quality under the 

CWA and to protect human health and the 

environment under RCRA are fulfilled. At the same 

time, the EPA would seek to minimize the potential 

existing fossil fuel-fired EGUs: The 

steam electric effluent limitation 

guidelines (SE ELG) rule and the coal 

combustion residuals (CCR) rule. These 

proposed rules are summarized below. 

On June 7, 2013 (78 FR 34432), the 

EPA proposed the SE ELG rule to 

strengthen the controls on discharges 

from certain steam electric power plants 

by revising technology-based effluent 

limitations guidelines and standards for 

the steam electric power generating 

point source category. The current 

regulations, which were last updated in 

1982, do not adequately address the 

toxic pollutants discharged from the 

electric power industry, nor have they 

kept pace with process changes that 

have occurred over the last three 

decades. Existing steam electric power 

plants currently contribute 50–60 

percent of all toxic pollutants 

discharged to surface waters by all 

industrial categories regulated in the 

United States under the CWA. 

Furthermore, power plant discharges to 

surface waters are expected to increase 

as pollutants are increasingly captured 

by air pollution controls and transferred 

to wastewater discharges. This proposed 

regulation, which includes new 

requirements for both existing and new 

generating units, would reduce the 

amount of toxic metals and other 

pollutants discharged to surface waters 

from power plants. 

On June 21, 2010 (75 FR 35128), the 

EPA proposed the CCR rule, which coproposed two approaches to regulating 

the disposal of coal combustion 

residuals (CCRs) generated by electric 

utilities and independent power 

producers. CCRs are residues from the 

combustion of coal in steam electric 

power plants and include materials 

such as coal ash (fly ash and bottom 

ash) and flue gas desulfurization (FGD) 

wastes. Under one proposed approach, 

the EPA would list these residuals as 

‘‘special wastes,’’ when destined for 

disposal in landfills or surface 

impoundments, and would apply the 

existing regulatory requirements 

established under Subtitle C of RCRA to 

such wastes. Under the second 

proposed approach, the EPA would 

establish new regulations applicable 

specifically to CCRs under subtitle D of 

RCRA, the section of the statute 

applicable to solid (i.e., non-hazardous) 

wastes. Under both approaches, CCRs 

that are beneficially used would remain 

exempt under the Bevill exclusion.321

While the EPA still is evaluating all the 

available information and comments, 

and while a final risk assessment for the 

CCR rule has not yet been completed, 

reliance on data and analyses discussed 

in the preamble to the recent SE ELG 

proposal might have the potential to 

lower the CCR rule risk assessment 

results by as much as an order of 

magnitude. If this proves to be the case, 

the EPA’s current thinking is that the 

revised risks, coupled with the ELG 

requirements that the agency might 

promulgate, and the increased federal 

oversight such requirements could 

achieve, could provide strong support 

for a conclusion that regulation of CCR 

disposal under RCRA Subtitle D would 

be adequate.322 The EPA is under a 

court-ordered deadline to complete the 

CCR rulemaking by December 19, 2014. 

The EPA recognizes the importance of 

assuring that each of the rules described 

above can achieve its intended 

environmental objectives in a 

commonsense, cost-effective manner, 

consistent with underlying statutory 

requirements, and while assuring a 

reliable power system. Executive Order 

(EO) 13563, ‘‘Improving Regulation and 

Regulatory Review,’’ issued on January 

18, 2011, states that ‘‘[i]n developing 

regulatory actions and identifying 

appropriate approaches, each agency 

shall attempt to promote . . . 

coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve regulatory goals that are 

designed to promote innovation.’’ 

Within the EPA, we are paying careful 

attention to the interrelatedness and 

potential impacts on the industry, 

reliability and cost that these various 

rulemakings can have. 

As discussed in Sections VII and VIII 

of this preamble, the EPA is proposing 

to give states broad flexibility in 

developing approvable plans under 

CAA section 111(d), including the 

ability to adopt rate-based or mass-based 

emission performance goals, and to rely 

on a wide variety of CO2 emission 

reduction measures. The EPA is also 

proposing to give states considerable 

flexibility with respect to the 

timeframes for plan development and 

implementation, with up to two or three 

years permitted for final plans to be 

submitted after the proposed GHG 

emission guidelines are finalized, and 

up to fifteen years for all emission 

reduction measures to be fully 

implemented. In light of these 

flexibilities, we believe that states will 

have ample opportunity, when 

developing and implementing their 

CAA section 111(d) plans, to coordinate 

their response to this requirement with 

source and state responses to any 

obligations that may be applicable to 

affected EGUs as a result of the MATS, 

316(b), SE ELG and CCR rules—all of 

which are or will be final rules before 

this rulemaking is finalized—and to do 

so in a manner that will help reduce 

cost and ensure reliability, while also 

ensuring that all applicable 

environmental requirements are met.323

The EPA is also endeavoring to enable 

EGUs to comply with applicable 

obligations under other power sector 

rules as efficiently as possible (e.g., by 

facilitating their ability to coordinate 

planning and investment decisions with 

respect to those rules) and, where 

possible, implement integrated 

compliance strategies. For example, in 

the proposed SE ELG rule, the EPA 

describes its current thinking on how it 

might effectively harmonize the 

potential requirements of that rule with 

the requirements of the final CCR rule, 

to the extent that both rules may 

regulate or affect the disposal of coal 

combustion wastes to and from surface 

impoundments at power plants.324 The 

EPA’s goal in exploring how it might 

harmonize the SE ELG and CCR rules is 

to minimize the overall complexity of 

the two regulatory structures and avoid 

creating unnecessary burdens.325


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for overlapping requirements to avoid imposing any 

unnecessary burdens on regulated entities and to 

facilitate implementation and minimize the overall 

complexity of the regulatory structure under which 

facilities must operate. Based on these 

considerations, the EPA stated that it is exploring 

two primary means of integrating the two rules: (1) 

Through coordinating the design of any final 

substantive CCR regulatory requirements, and (2) 

through coordination of the timing and 

implementation of final rule requirements to 

provide facilities with a reasonable timeline for 

implementation that allows for coordinated 

planning and protects electricity reliability for 

consumers. 

326The EPA has developed a comprehensive 

implementation strategy for these future actions 

that focuses resources on identifying and 

addressing unhealthy levels of SO2 in areas where 

people are most likely to be exposed to violations 

of the standard. The strategy is available at: http:// 

www.epa.gov/airquality/sulfurdioxide/ 

implement.html. 

327The impacts presented in this section of the 

preamble represent an illustrative implementation 

of the guidelines. As states implement the proposed 

guidelines, they have sufficient flexibility to adopt 

different state-level or regional approaches that may 

yield different costs, benefits, and environmental 

impacts. For example, states may use the 

flexibilities described in these guidelines to find 

approaches that are more cost effective for their 

particular state or choose approaches that shift the 

balance of co-benefits and impacts to match broader 

state priorities. 

In addition to the power sector rules 

discussed above, the development of 

SIPs for criteria pollutants (PM2.5, ozone 

and SO2) and regional haze may also 

have implications for existing fossilfired EGUs. 

On June 6, 2013, the EPA proposed an 

implementation rule for the 2008 ozone 

National Ambient Air Quality Standards 

(NAAQS), to provide rules and guidance 

to states on the development of 

approvable state implementation plans 

(SIPs), including SIPs under CAA 

section 110 (infrastructure SIPs) and 

section 182 (ozone nonattainment SIPs). 

This rule addresses the statutory 

requirements for areas that the EPA has 

designated as nonattainment for the 

2008 ozone standard. The agency is 

currently working to finalize that rule. 

The EPA is also working on a proposed 

transport rule that would identify the 

obligations of upwind states that 

contribute to those downwind state 

ozone nonattainment areas. This rule is 

scheduled for proposal in 2014 and to 

be finalized by 2015. 

The EPA is developing a proposed 

implementation rule to provide 

guidance to states on the development 

of SIPs for the 2012 PM2.5 NAAQS. 

The SO2 NAAQS was revised in June 

2010 to protect public health from the 

short-term effects of SO2 exposure. In 

July 2013, the EPA designated 29 areas 

in 16 states as nonattainment for the 

SO2 NAAQS. The EPA based these 

nonattainment designations on the most 

recent set of certified air quality 

monitoring data as well as an 

assessment of nearby emission sources 

and weather patterns that contribute to 

the monitored levels. The EPA intends 

to address the designations for all other 

areas in separate actions in the 

future 326. The EPA has proposed the 

data requirements rule for the 1-hour 

SO2 NAAQS to require states to 

characterize air quality more extensively 

using ambient monitoring or air quality 

modeling approaches. 

The EPA requires SIP updates every 

10 years for regional haze, as required 

by the EPA’s Regional Haze Rule which 

was promulgated in 1999. The next 10- 

year SIP revision for regional haze, 

covering the time period through 2028, 

is due from each state by July 2018. 

Each SIP must provide for reasonable 

progress towards visibility improvement 

in protected scenic areas. 

The development of these SIPs may, 

where applicable, have significant 

implications for existing fossil fuel-fired 

EGUs, as well as for the states that are 

responsible for developing them. The 

timeframes for submittal of SIPs for the 

various programs and the timeframes we 

are proposing for submittal of the CAA 

section 111(d) state plans will allow 

considerable time for coordination by 

states in the development of their 

respective plans. The EPA is willing to 

work with states to assist them in 

coordinating their efforts across these 

planning processes. The EPA believes 

that CAA section 111(d) efforts and 

actions will tend to contribute to overall 

air quality improvements and thus 

should be complementary to criteria 

pollutant and regional haze SIP efforts. 

In light of the broad flexibilities we 

are proposing in this action, we believe 

that states will have ample opportunity 

to design CAA section 111(d) plans that 

use innovative, cost-effective regulatory 

strategies and that spark investment and 

innovation across a wide variety of 

clean energy technologies. We also 

believe that the broad flexibilities we 

are proposing in this action will enable 

states and affected EGUs to build on 

their longstanding, successful records of 

complying with multiple CAA, CWA, 

and other environmental requirements, 

while assuring an adequate, affordable, 

and reliable supply of electricity. 

X. Impacts of the Proposed Action 327

A. What are the air impacts? 

The EPA anticipates significant 

emission reductions under the proposed 

guidelines for the power sector. CO2

emissions are projected to be reduced 

when compared to 2005 emissions, by 

26 percent to 27 percent in 2020 and 

about 30 percent in 2030 under Option 

1. Option 2 reflects reductions of about 

23 percent in 2020 and 23 percent to 24 

percent in 2025 when compared to CO2

emissions in 2005. The guidelines are 

projected to result in substantial cobenefits through reductions of SO2, 

PM2.5 and NOx that will have direct 

public health benefits by lowering 

ambient levels of these pollutants and 

ozone. Tables 10 and 11 show expected 

CO2 and other air pollutant emission 

reductions in the base case, with the 

proposed Option 1 for 2020, 2025, and 

2030 and regulatory alternative Option 

2, for 2020 and 2025. 

TABLE 10—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 1 

CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX

(thousands 

of tons) 

PM2.5

(thousands 

of tons) 

2020 Regional Compliance Approach: 

Base Case Proposed ............................................................................... 2,161 1,476 1,559 212 

Guidelines: 1,790 1,184 1,213 156 

Emission Reductions ................................................................................ 371 292 345 56 

2025 Regional Compliance Approach: 

Base Case Proposed ............................................................................... 2,231 1,515 1,587 209 

Guidelines: 1,730 1,120 1,166 150 


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TABLE 10—SUMMARY OF CO2 AND OTHER AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 1—Continued 

CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX

(thousands 

of tons) 

PM2.5

(thousands 

of tons) 

Emission Reductions ................................................................................ 501 395 421 59 

2030 Regional Compliance Approach: 

Base Case Proposed ............................................................................... 2,256 1,530 1,537 198 

Guidelines: 1,711 1,106 1,131 144 

Emission Reductions ................................................................................ 545 424 407 54 

2020 State Compliance Approach: 

Base Case Proposed ............................................................................... 2,161 1,476 1,559 212 

Guidelines: 1,777 1,140 1,191 154 

Emission Reductions ................................................................................ 383 335 367 58 

2025 State Compliance Approach: 

Base Case Proposed ............................................................................... 2,231 1,515 1,587 209 

Guidelines: 1,724 1,090 1,151 145 

Emission Reductions ................................................................................ 506 425 436 63 

2030 State Compliance Approach: 

Base Case Proposed ............................................................................... 2,256 1,530 1,537 198 

Guidelines: 1,701 1,059 1,109 142 

Emission Reductions ................................................................................ 555 471 428 56 

Source: Integrated Planning Model, 2014. 

TABLE 11—SUMMARY OF CO2 AND AIR POLLUTANT EMISSION REDUCTIONS WITH OPTION 2 

CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX

(thousands 

of tons) 

PM2.5

(thousands 

of tons) 

2020 Regional Compliance Approach: 

Base Case ................................................................................................ 2,161 1,476 1,559 212 

Option 2 .................................................................................................... 1,878 1,231 1,290 166 

Emission Reductions ................................................................................ 283 244 268 46 

2025 Regional Compliance Approach: 

Base Case ................................................................................................ 2,231 1,515 1,587 209 

Option 2 .................................................................................................... 1,862 1,218 1,279 165 

Emission Reductions ................................................................................ 368 297 309 44 

2020 State Compliance Approach: 

Base Case ................................................................................................ 2,161 1,476 1,559 212 

Option 2 .................................................................................................... 1,866 1,208 1,277 163 

Emission Reductions ................................................................................ 295 267 281 49 

2025 State Compliance Approach: 

Base Case ................................................................................................ 2,231 1,515 1,587 209 

Option 2 .................................................................................................... 1,855 1,188 1,271 161 

Emission Reductions ................................................................................ 376 327 317 48 

Source: Integrated Planning Model, 2014. 

The reductions in these tables do not 

account for reductions in hazardous air 

pollutants (HAPs) that may occur as a 

result of this rule. For instance, the fine 

particulate reductions presented above 

do not reflect all of the reductions in 

many heavy metal particulates. 

B. Comparison of Building Block 

Approaches 

Though the EPA has determined that 

the 4-building block approach is the 

BSER, we did analyze the impacts of 

both a combination of building blocks 1 

and 2 and the combination of all four 

building blocks. The analysis indicates 

that the combined strategies of heat rate 

improvements (building block 1) and redispatch (building block 2) would result 

in overall CO2 emission reductions of 

approximately 22 percent in 2020 

(compared to 2005 emissions and 


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328Note that the health co-benefits and net 

benefits for the proposed Option 1 include PM cobenefits associated with directly emitted PM2.5. In 

contrast, the building block 1 and 2 analysis does 

not include co-benefits related to directly emitted 

PM2.5. 

329See, e.g., 73 FR 28212, 28300 (May 15, 2008); 

Memorandum from David Longly Bernhardt, 

Solicitor, U.S. Department of the Interior re: 

‘‘Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to 

Proposed Actions Involving the Emission of 

Greenhouse Gases’’ (Oct. 3, 2008). 

assuming state-level compliance). This 

compares to expected CO2 emission 

reductions of approximately 27 percent 

for the four-block BSER approach 

discussed below. The EPA analysis also 

estimates 24–32 GW of additional coalfired EGU retirements in 2020 

(compared to 46–49 GW for the fourblock approach) and an additional 3–5 

GW of oil/gas steam EGUs (compared to 

16 GW for the four-block approach). For 

both the two-block and the four-block 

approach, a decrease in coal production 

and price is predicted in 2020. The 

decrease in production is predicted at 

20–23 percent for the two-block 

approach, compared to a decrease of 25– 

27 percent for the four-block approach. 

A 12 percent decrease in coal prices is 

predicted for the two-block approach; 

while the four-block approach results in 

a 16 to 18 percent decrease. Under both 

approaches, the shifting in generation 

from higher-emitting steam EGUs to 

lower-emitting NGCC units results in an 

increase in natural gas production and 

price. The two-block approach results in 

a production increase of 19–22 percent 

and a price increase of 10–11 percent. 

The four-block approach results in a 

production increase of 12–14 percent 

and a price increase of 9–12 percent. 

Both the two-block and the four-block 

approaches result in construction of 

additional NGCC capacity by 2020, with 

11–18 GW of new NGCC for the twoblock approach and 20–22 GW of new 

NGCC capacity for the four-block 

approach. However, while the two-block 

approach results in 5–17 GW of new 

NGCC capacity in 2030, the four-block 

approach results in 32–35 GW less 

NGCC capacity in 2030 relative to the 

base case (due to increased use of 

renewable energy sources and decreased 

demand from implementation of 

demand side energy efficiency 

measures). Also, significantly, the twoblock approach results in less than 500 

MW of new renewable energy capacity; 

while the four-block option results in 

approximately 12 GW of new renewable 

generating capacity. 

The EPA projects that the annual 

incremental compliance cost for the 

building block 1 and 2 approach is 

estimated to be $3.2 to $4.4 billion in 

2020 and $6.8 to $9.8 billion (2011$) in 

2030, excluding the costs associated 

with monitoring, reporting, and 

recordkeeping (MRR). This compares to 

costs excluding MRR of $5.4 to $7.4 

billion in 2020 and $7.3 to $8.8 billion 

in 2030 for the proposed Option 1 

(2011$) as discussed in Section X.E of 

this preamble. 

The total combined climate benefits 

and health co-benefits for the building 

block 1 and 2 approach are estimated to 

be $21 to $40 billion in 2020 and $32 

to $63 billion in 2030 (2011$ at a 3- 

percent discount rate [model average]). 

The net benefits are estimated to be $18 

to $36 billion in 2020 and $25 to $53 

billion in 2030 (2011$ at a 3-percent 

discount rate [model average]). For the 

purposes of this summary, we list the 

climate benefits associated with the 

marginal value of the model average at 

3% discount rate, however we 

emphasize the importance and value of 

considering the full range of SCC values. 

These building block 1 and 2 benefit 

estimates compare to combined climate 

benefits and health co-benefits of $33 to 

$57 billion in 2020 and $55 to $93 

billion in 2030 (2011$ at a 3-percent 

discount rate [model average]) for the 

proposed Option 1. Net benefits are 

estimated to be $27 to $50 billion in 

2020 and $48 to $84 billion in 2030 

(2011$ at a 3-percent discount rate 

[model average]) as discussed in Section 

X.G. and XI.A of this preamble.328

C. Endangered Species Act 

Consistent with the requirements of 

section 7(a)(2) of the Endangered 

Species Act (ESA), the EPA has also 

considered the effects of this proposed 

rule and has reviewed applicable ESA 

regulations, case law, and guidance to 

determine what, if any, impact there 

may be to listed endangered or 

threatened species or designated critical 

habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in 

consultation with the U.S. Fish and 

Wildlife Service (FWS) and/or the 

National Marine Fisheries Service, to 

ensure that actions they authorize, fund, 

or carry out are not likely to jeopardize 

the continued existence of federally 

listed endangered or threatened species 

or result in the destruction or adverse 

modification of designated critical 

habitat of such species. 16 U.S.C. 

1536(a)(2). Under relevant 

implementing regulations, section 

7(a)(2) applies only to actions where 

there is discretionary federal 

involvement or control. 50 CFR 402.03. 

Further, under the regulations 

consultation is required only for actions 

that ‘‘may affect’’ listed species or 

designated critical habitat. 50 CFR 

§ 402.14. Consultation is not required 

where the action has no effect on such 

species or habitat. Under this standard, 

it is the federal agency taking the action 

that evaluates the action and determines 

whether consultation is required. See 51 

FR 19926, 19949 (June 3, 1986). Effects 

of an action include both the direct and 

indirect effects that will be added to the 

environmental baseline. 50 CFR 402.02. 

Indirect effects are those that are caused 

by the action, later in time, and are 

reasonably certain to occur. Id. To 

trigger a consultation requirement, there 

must thus be a causal connection 

between the federal action, the effect in 

question, and the listed species, and the 

effect must be reasonably certain to 

occur. 

The EPA has considered the effects of 

this proposed rule and has reviewed 

applicable ESA regulations, case law, 

and guidance to determine what, if any, 

impact there may be to listed species or 

designated critical habitat for purposes 

of section 7(a)(2) consultation. The EPA 

notes that the projected environmental 

effects of this proposal are positive: 

reductions in overall GHG emissions, 

and reductions in PM and ozoneprecursor emissions (SOX and NOX). 

With respect to the projected GHG 

emission reductions, the EPA does not 

believe that such reductions trigger ESA 

consultation requirements under section 

7(a)(2). In reaching this conclusion, the 

EPA is mindful of significant legal and 

technical analysis undertaken by FWS 

and the U.S. Department of the Interior 

in the context of listing the polar bear 

as a threatened species under the ESA. 

In that context, in 2008, FWS and DOI 

expressed the view that the best 

scientific data available were 

insufficient to draw a causal connection 

between GHG emissions and effects on 

the species in its habitat.329 The DOI 

Solicitor concluded that where the 

effect at issue is climate change, 

proposed actions involving GHG 

emissions cannot pass the ‘‘may affect’’ 

test of the section 7 regulations and thus 

are not subject to ESA consultation. The 

EPA has also previously considered 

issues relating to GHG emissions in 

connection with the requirements of 

ESA section 7(a)(2). Although the GHG 

emission reductions projected for this 

proposal are large (the highest estimate 

is reductions of 555 MMT of CO2 in 

2030—see Table 10 above), the EPA 

evaluated larger reductions in assessing 

this same issue in the context of the 

light duty vehicle GHG emission 

standards for model years 2012–2016 

and 2017–2025. There the agency 

projected emission reductions roughly 

double and four times those projected 


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330See 75 FR at 25438 Table I.C 2–4 (May 7, 

2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012). 

here over the lifetimes of the model 

years in question 330 and, based on air 

quality modeling of potential 

environmental effects, concluded that 

‘‘EPA knows of no modeling tool which 

can link these small, time-attenuated 

changes in global metrics to particular 

effects on listed species in particular 

areas. Extrapolating from global metric 

to local effect with such small numbers, 

and accounting for further links in a 

causative chain, remain beyond current 

modeling capabilities.’’ EPA, Light Duty 

Vehicle Greenhouse Gas Standards and 

Corporate Average Fuel Economy 

Standards, Response to Comment 

Document for Joint Rulemaking at 4–102 

(Docket EPA–OAR–HQ–2009–4782). 

The EPA reached this conclusion after 

evaluating issues relating to potential 

improvements relevant to both 

temperature and oceanographic pH 

outputs. The EPA’s ultimate finding was 

that ‘‘any potential for a specific impact 

on listed species in their habitats 

associated with these very small 

changes in average global temperature 

and ocean pH is too remote to trigger the 

threshold for ESA section 7 (a)(2).’’ Id. 

The EPA believes that the same 

conclusions apply to the present 

proposal, given that the projected CO2

emission reductions are less than those 

projected for either of the light duty 

vehicle rules. See, e.g., Ground Zero 

Center for Non-Violent Action v. U.S. 

Dept. of Navy, 383 F. 3d 1082, 1091–92 

(9th Cir. 2004) (where the likelihood of 

jeopardy to a species from a federal 

action is extremely remote, ESA does 

not require consultation). 

With regard to non-GHG air 

emissions, the EPA is also projecting 

substantial reductions of SOX and NOX

as a collateral consequence of this 

proposal. However, CAA section 

111(d)(1) standards cannot directly 

control emissions of criteria pollutants. 

Consequently, CAA section 111(d) 

provides no discretion to adjust the 

standard based on potential impacts to 

endangered species of reduced criteria 

pollutant emissions. Section 7(a)(2) 

consultation thus is not required with 

respect to the projected reductions of 

criteria pollutant emissions. See 50 CFR 

402.03; see also, National Lime Ass’n v. 

EPA, 233 F. 3d 625, 638–39 (D.C. Cir. 

2000) (although CAA section 112(b)(2) 

prohibits the EPA from listing criteria 

pollutants as hazardous air pollutants, 

the EPA may use PM as a surrogate for 

metal hazardous air pollutants and 

reductions in PM do not constitute 

impermissible regulation of a criteria 

pollutant). 

Moreover, there are substantial 

questions as to whether any potential 

for relevant effects results from any 

element of the proposed rule or would 

result instead from the separate actions 

of States establishing standards of 

performance for existing sources and 

implementing and enforcing those 

standards. Cf. American Trucking 

Assn’s v. EPA, 175 F. 3d 1027, 1043–45 

(D.C. Cir. 1999), rev’d on different 

grounds sub nom., Whitman v. 

American Trucking Assn’s, 531 U.S. 457 

(2000) (National Ambient Air Quality 

Standards have no economic impact, for 

purposes of Regulatory Flexibility Act, 

because impacts result from the actions 

of States through their development, 

implementation and enforcement of 

state implementation plans). Thus, for 

example, although questions may exist 

whether actions such as increased 

utilization of solar or wind power could 

have effects on listed species, the EPA 

believes that such effects (if any) would 

result from decisions and actions by 

states in developing, implementing and 

enforcing their plans. The precise steps 

States choose to take in that regard 

cannot be determined or ordered by this 

federal action, and they are not 

sufficiently certain to be attributable to 

this proposed rule for ESA purposes. 

Consequently, for this additional reason, 

the EPA does not believe that this 

proposed rule (if enacted) would have 

effects on listed species that would 

trigger the section 7 (a)(2) consultation 

requirement. 

D. What are the energy impacts? 

The proposed guidelines have 

important energy market implications. 

Under Option 1, average nationwide 

retail electricity prices are projected to 

increase by roughly 6 to 7 percent in 

2020 relative to the base case, and by 

roughly 3 percent in 2030 (contiguous 

U.S.). Average monthly electricity bills 

are anticipated to increase by roughly 3 

percent in 2020, but decline by 

approximately 9 percent by 2030. This 

is a result of the increasing penetration 

of demand-side programs that more than 

offset increased prices to end users by 

their expected savings from reduced 

electricity use. 

The average delivered coal price to 

the power sector is projected to decrease 

by 16 to 17 percent in 2020 and roughly 

18 percent in 2030, relative to the base 

case for Option 1. The EPA also projects 

that electric power sector-delivered 

natural gas prices will increase by 9 to 

12 percent in 2020, with negligible 

changes in 2030. Natural gas use for 

electricity generation will increase by as 

much as 1.2 trillion cubic feet (TCF) in 

2020 relative to the base case, and then 

begin to decline over time. 

These figures reflect the EPA’s 

illustrative modeling that presumes 

policies that lead to dispatch changes in 

2020 and growing use of energy 

efficiency and renewable electricity 

generation out to 2029. If states make 

different policy choices, impacts could 

be different. For instance, if states 

implement renewable and/or energy 

efficiency policies on a more aggressive 

time-frame, impacts on natural gas and 

electricity prices would likely be less. 

Implementation of other measures not 

included in the EPA’s BSER calculation 

or compliance modeling, such as 

nuclear uprates, transmission system 

improvements, use of energy storage 

technologies or retrofit CCS, could also 

mitigate gas price and/or electricity 

price impacts. 

The EPA projects coal production for 

use by the power sector, a large 

component of total coal production, will 

decline by roughly 25 to 27 percent in 

2020 from base case levels. The use of 

coal by the power sector will decrease 

roughly 30 to 32 percent in 2030. 

Renewable energy capacity is 

anticipated to increase by roughly 12 

GW in 2020 and by 9 GW in 2030 under 

Option 1. Energy market impacts from 

the guidelines are discussed more 

extensively in the RIA found in the 

docket for this rulemaking. 

E. What are the compliance costs? 

The compliance costs of this proposed 

action are represented in this analysis as 

the change in electric power generation 

costs between the base case and the 

proposed rule in which states pursue a 

distinct set of strategies beyond the 

strategies taken in the base case to meet 

the terms of the EGU GHG emission 

guidelines, and include cost estimates 

for demand-side energy efficiency. The 

compliance assumptions—and, 

therefore, the projected compliance 

costs—set forth in this analysis are 

illustrative in nature and do not 

represent the full suite of compliance 

flexibilities states may ultimately 

pursue. These illustrative compliance 

scenarios are designed to reflect, to the 

extent possible, the scope and the 

nature of the proposed guidelines. 

However, there is considerable 

uncertainty with regards to the precise 

measures that states will adopt to meet 

the proposed requirements, because 

there are considerable flexibilities 

afforded to the states in developing their 

state plans. 

The EPA projects that the annual 

incremental compliance cost of Option 

1 is estimated to be between $5.5 and 

$7.5 billion in 2020 and between $7.3 


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and $8.8 billion (2011$) in 2030, 

including the costs associated with 

monitoring, reporting, and 

recordkeeping (MRR). The incremental 

compliance cost of Option 2 is 

estimated to be between $4.3 and $5.5 

billion in 2020, including MRR costs. In 

2025, the estimated compliance cost of 

Option 2 is estimated to be between $4.5 

and $5.5 billion (with the assumed 

levels of end-use energy efficiency). 

These important dynamics are 

discussed in more detail in the RIA in 

the rulemaking docket. The annualized 

incremental cost is the projected 

additional cost of complying with the 

guidelines in the year analyzed, and 

includes the amortized cost of capital 

investment, needed new capacity, shifts 

between or amongst various fuels, 

deployment of energy efficiency 

programs, and other actions associated 

with compliance. MRR costs are 

estimated to be $68.3 million (2011$) in 

2020 and $8.9 million in 2025 and 2030 

for Option 1 and $68.3 million in 2020 

and $8.9 million in 2025 for Option 2. 

More detailed cost estimates are 

available in the RIA included in the 

rulemaking docket. 

F. What are the economic and 

employment impacts? 

The proposed standards are projected 

to result in certain changes to power 

system operation as a result of the 

application of state emission rate goals. 

Overall, we project dispatch changes, 

changes to fossil fuel and retail 

electricity prices, and some additional 

coal retirements. Average electric power 

sector-delivered natural gas prices are 

projected to increase by roughly 9 to 12 

percent in 2020 in Option 1, with 

negligible changes by 2030. Under 

Option 2, electric power sector natural 

gas prices are projected to increase by 

roughly 8 percent in 2020, on an average 

nationwide basis, and increase by 1 

percent or less in 2025. The average 

delivered coal price to the power sector 

is projected to decrease by 16 to 17 

percent in 2020 under Option 1, and 

decrease by roughly 14 percent under 

Option 2, on a nationwide average basis. 

Retail electricity prices are projected to 

increase 6 to 7 percent under Option 1 

and increase by roughly 4 percent under 

Option 2, both in 2020 and on an 

average basis across the contiguous U.S. 

By 2030 under Option 1, electricity 

prices are projected to increase by about 

3 percent. Under Option 1, the EPA 

projects 46 to 50 GW of additional coalfired generation may be uneconomic to 

maintain and may be removed from 

operation by 2030. The EPA projects 

that under Option 2, 30 to 33 GW of 

additional coal-fired generation may be 

uneconomic to maintain and may be 

removed from operation by 2025. 

It is important to note that the EPA’s 

modeling does not necessarily account 

for all of the factors that may influence 

business decisions regarding future coal 

fired capacity. By 2025, the average age 

of the coal-fired fleet will be 49 years 

old and twenty percent of the fleet will 

be more than 60 years old. Many power 

companies already factor a carbon price 

into their long term capacity planning 

that would further influence business 

decisions to replace these aging assets 

with modern, and significantly cleaner 

generation. 

The compliance modeling done to 

support the proposal assumes that 

overall electric demand will decrease 

significantly, as states ramp up 

programs that result in lower overall 

demand. End-use energy efficiency 

levels increase such that they achieve 

about an 11 percent reduction on overall 

electricity demand levels in 2030 for 

Option 1, and a reduction in overall 

electricity demand of approximately 6 

percent reduction in 2025 for Option 2. 

In response, there are anticipated to be 

notable changes to costs, prices, and 

electricity generation in the power 

sector as more end-use efficiency is 

realized. 

Changes in price or demand for 

electricity, natural gas, coal, can impact 

markets for goods and services 

produced by sectors that use these 

energy inputs in the production process 

or supply those sectors. Changes in cost 

of production may result in changes in 

price, changes in quantity produced, 

and changes in profitability of firms 

affected. The EPA recognizes that these 

guidelines provide significant 

flexibilities and states implementing the 

guidelines may choose to mitigate 

impacts to some markets outside the 

EGU sector. Similarly, demand for new 

generation or energy efficiency can 

result in shifts in production and 

profitability for firms that supply those 

goods and services, and the guidelines 

provide flexibility for states that may 

want to enhance demand for goods and 

services from those sectors. 

Executive Order 13563 directs federal 

agencies to consider the effect of 

regulations on job creation and 

employment. According to the 

Executive Order, ‘‘our regulatory system 

must protect public health, welfare, 

safety, and our environment while 

promoting economic growth, 

innovation, competitiveness, and job 

creation. It must be based on the best 

available science.’’ (Executive Order 

13563, 2011) Although standard benefitcost analyses have not typically 

included a separate analysis of 

regulation-induced employment 

impacts, we typically conduct 

employment analyses. During periods of 

sustained high unemployment, 

employment impacts are of particular 

concern and questions may arise about 

their existence and magnitude. 

States have the responsibility and 

flexibility to implement policies and 

practices for compliance with Proposed 

Electric Generating Unit Greenhouse 

Gas Existing Source Guidelines. 

Quantifying the associated employment 

impacts is complicated by the wide 

range of approaches that States may use. 

As such, the EPA’s employment 

analysis includes projected employment 

impacts associated with illustrative 

compliance scenarios for these 

guidelines for the electric power 

industry, coal and natural gas 

production, and demand-side energy 

efficiency activities. These projections 

are derived, in part, from a detailed 

model of the electricity production 

sector used for this regulatory analysis, 

and U.S government data on 

employment and labor productivity. In 

the electricity, coal, and natural gas 

sectors, the EPA estimates that these 

guidelines could have an employment 

impact of roughly 25,900 to 28,000 jobyears increase in 2020 for Option 1, 

state to regional compliance approach, 

respectively. For Option 2, the state and 

regional compliance approach estimates 

are 26,700 to 29,800 job-years increase 

in 2020. Demand-side energy efficiency 

employment impacts are approximately 

an increase of 78,800 jobs in 2020 for 

Option 1 and of 57,000 jobs for Option 

2. By its nature, energy efficiency 

reduces overall demand for electric 

power. The EPA recognizes as more 

efficiency is built into the U.S. power 

system over time, lower fuel 

requirements may lead to fewer jobs in 

the coal and natural gas extraction 

sectors, as well as in EGU construction 

and operation than would otherwise 

have been expected. The EPA also 

recognizes the fact that, in many cases, 

employment gains and losses that might 

be attributable to this rule would be 

expected to affect different sets of 

people. Moreover, workers who lose 

jobs in these sectors may find 

employment elsewhere just as workers 

employed in new jobs in these sectors 

may have been previously employed 

elsewhere. Therefore, the employment 

estimates reported in these sectors may 

include workers previously employed 

elsewhere. This analysis also does not 

capture potential economy-wide 

impacts due to changes in prices (of 

fuel, electricity, labor, etc.). For these 

reasons, the numbers reported here 


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34936 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

should not be interpreted as a net 

national employment impact. 

G. What are the benefits of the proposed 

goals? 

Implementing the proposed standards 

will generate benefits by reducing 

emissions of CO2 as well as criteria 

pollutants and their precursors, 

including SO2, NOX and directly 

emitted particles. SO2 and NOX are 

precursors to PM2.5 (particles smaller 

than 2.5 microns), and NOX is a 

precursor to ozone. The estimated 

benefits associated with these emission 

reductions are beyond those achieved 

by previous EPA rulemakings including 

the Mercury and Air Toxics Standards 

rule. The health and welfare benefits 

from reducing air pollution are 

considered co-benefits for these 

standards. For this rulemaking, we were 

only able to quantify the climate 

benefits from reduced emissions of CO2

and the health co-benefits associated 

with reduced exposure to PM2.5 and 

ozone. In summary, we estimate the 

total combined climate benefits and 

health co-benefits for Option 1 to be $33 

billion to $54 billion in 2020 and $55 

billion to $89 billion in 2030 assuming 

a regional compliance approach (2011 

dollars at a 3-percent discount rate 

[model average]). If states comply using 

a state-specific compliance approach, 

these climate and health co-benefits 

estimates are estimated to be $35 to $57 

billion in 2020 and $57 to $93 billion 

in 2030 (2011 dollars at a 3-percent 

discount rate [model average]). We also 

estimate the total combined climate 

benefits and health co-benefits for 

Option 2 to be $26 billion to $44 billion 

in 2020 and $36 billion to $59 billion 

in 2025 (regional compliance approach, 

2011 dollars at a 3-percent discount rate 

[model average]). Assuming a state 

compliance approach, the total 

combined climate benefits and health 

co-benefits for Option 2 are estimated to 

be $27 billion to $45 billion in 2020 and 

$36 billion to $60 billion in 2025 (2011 

dollars at a 3-percent discount rate 

[model average]). A summary of the 

emission reductions and monetized 

benefits estimated for this rule at all 

discount rates and additional analysis 

years is provided in Tables 12 through 

17 of this preamble. 

TABLE 12—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE PROPOSED OPTION 1 

[Billions of 2011 dollars] a

2020 Discount rate 

(statistic) 

Monetized climate benefits 

Regional 

compliance 

State 

compliance 

CO2 Reductions (million metric tons) ....................... ................................................................................... 371 383 

5 percent (average SCC) ......................................... $4.7 $4.9 

3 percent (average SCC) ......................................... $17 $18 

2.5 percent (average SCC) ...................................... $25 $26 

3 percent (95th percentile SCC) .............................. $51 $52 

2025 

CO2 Reductions (million metric tons) ....................... ................................................................................... 501 506 

5 percent (average SCC) ......................................... $7.5 $7.6 

3 percent (average SCC) ......................................... $25 $25 

2.5 percent (average SCC) ...................................... $37 $37 

3 percent (95th percentile SCC) .............................. $76 $77 

2030 

CO2 Reductions (million metric tons) ....................... ................................................................................... 545 555 

5 percent (average SCC) ......................................... $9.3 $9.5 

3 percent (average SCC) ......................................... $30 $31 

2.5 percent (average SCC) ...................................... $44 $44 

3 percent (95th percentile SCC) .............................. $92 $94 

a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account for 

changes in non-CO2 GHG emissions. These estimates are based on the global social cost of carbon (SCC) estimates for the analysis years 

(2020, 2025, and 2030) and are rounded to two significant figures. 

TABLE 13—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE OPTION 2 

[Billions of 2011 dollars] a

2020 Discount rate 

(statistic) 

Monetized climate benefits 

Regional 

compliance 

State 

compliance 

CO2 Reductions (million metric tons) ....................... ................................................................................... 283 295 

5 percent (average SCC) ......................................... $3.6 $3.8 

3 percent (average SCC) ......................................... $13 $14 

2.5 percent (average SCC) ...................................... $19 $20 

3 percent (95th percentile SCC) .............................. $39 $40 

2025 

CO2 Reductions (million metric tons) ....................... ................................................................................... 368 376 

5 percent (average SCC) ......................................... $5.5 $5.6 

3 percent (average SCC) ......................................... $18 $19 


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TABLE 13—SUMMARY OF THE MONETIZED GLOBAL CLIMATE BENEFITS FOR THE OPTION 2—Continued 

[Billions of 2011 dollars] a

2020 Discount rate 

(statistic) 

Monetized climate benefits 

Regional 

compliance 

State 

compliance 

2.5 percent (average SCC) ...................................... $27 $28 

3 percent (95th percentile SCC) .............................. $56 $57 

a Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the table and do not account for 

changes in non-CO2 GHG emissions. These estimates are based on the global SCC estimates for the analysis years (2020, 2025, and 2030) 

and are rounded to two significant figures. 

TABLE 14—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS FOR THE PROPOSED STANDARDS OPTION 1 REGIONAL

COMPLIANCE APPROACH IN THE U.S. 

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized 

health cobenefits 

(3 percent 

discount) 

Monetized 

health cobenefits 

(7 percent 

discount) 

Option 1 Regional Compliance Approach 2020 

PM2.5 precursors: b

SO2 ............................................................................................................................................................. 292 $12 to $26 $11 to $24 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) .............................................................. 6 $0.75 to $1.7 $0.67 to $1.5 

Directly emitted PM2.5 (crustal) .................................................................................................................. 44 $0.77 to $1.7 $0.69 to $1.6 

NOX ............................................................................................................................................................ 345 $2.2 to $5.0 $2.0 to $4.5 

Ozone precursor: c

NOX (ozone season only) .......................................................................................................................... 146 $0.63 to $2.7 $0.63 to $2.7 

Total Monetized Health Co-benefits ................................................................................................................................................. $16 to $37 $15 to $34 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d .......................................................................... $33 to $54 $32 to $51 

Option 1 Regional Compliance Approach 2025 

PM2.5 precursors b

SO2 ............................................................................................................................................................. 395 $17 to $38 $15 to $35 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) .............................................................. 6 $0.85 to $1.9 $0.76 to $1.7 

Directly emitted PM2.5 (crustal) .................................................................................................................. 46 $0.78 to $1.8 $0.70 to $1.6 

NOX ............................................................................................................................................................ 421 $3.0 to $6.8 $2.7 to $6.1 

Ozone precursor: c

NOX (ozone season only) ................................................................................................................................. 180 $1.0 to $4.3 $1.0 to $4.3 

Total Monetized Health Co-benefits ................................................................................................................................................. $23 to $53 $21 to $48 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d .......................................................................... $48 to $78 $46 to $74 

Option 1 Regional Compliance Approach 2030 

PM2.5 precursors: b

SO2 ............................................................................................................................................................. 424 $20 to $44 $18 to $40 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) .............................................................. 5 $0.84 to $1.9 $0.76 to $1.7 

Directly emitted PM2.5 (crustal) .................................................................................................................. 42 $0.77 to $1.7 $0.70 to $1.6 

NOX ............................................................................................................................................................ 407 $3.0 to $6.7 $2.7 to $6.1 

Ozone precursor: c

NOX(ozone season only) .................................................................................................................................. 176 $1.1 to $4.5 $1.1 to $4.5 

Total Monetized Health Co-benefits .......................................................................................................................................... $25 to $59 $23 to $54 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d .................................................................. $55 to $89 $53 to $84 

aAll estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as 

SO2, NOX and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of the 

range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation 

of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on a 

function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the same 

for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 


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TABLE 15—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE PROPOSED GUIDELINES OPTION 1 

STATE COMPLIANCE APPROACH

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized health co-benefits 

(3 percent discount) 

Monetized health co-benefits 

(7 percent discount) 

Option 1 State Compliance Approach in 2020 

PM2.5 precursors: b

SO2 ............................................................................................................ 335 $13 to $29 ....................................... $11 to $26 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) ............. 6 $0.76 to $1.7 ................................... $0.69 to $1.6 

Directly emitted PM2.5 (crustal) ................................................................. 45 $0.79 to $1.8 ................................... $0.71 to $1.6 

NOX ........................................................................................................... 367 $2.2 to $4.9 ..................................... $2.0 to $4.4 

Ozone precursor: c

NOX (ozone season only) ......................................................................... 157 $0.64 to $2.7 ................................... $0.64 to $2.7 

Total Monetized Health Co-benefits ............................................................................... $17 to $40 ....................................... $15 to $36 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ....... $35 to $57 ....................................... $33 to $54 

Option 1 State Compliance Approach in 2025 

PM2.5 precursors: b

SO2 ............................................................................................................ 425 $18 to $40 ....................................... $16 to $36 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) ............. 6 $0.90 to $2.0 ................................... $0.81 to $1.8 

Directly emitted PM2.5 (crustal) ................................................................. 49 $0.83 to $1.9 ................................... $0.75 to $1.7 

NOX ........................................................................................................... 436 $2.9 to $6.5 ..................................... $2.6 to $5.8 

Ozone precursor: c

NOX (ozone season only) ......................................................................... 190 $1.0 to $4.4 ..................................... $1.0 to $4.4 

Total Monetized Health Co-benefits ............................................................................... $23 to $54 ....................................... $21 to $49 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ....... $49 to $80 ....................................... $46 to $75 

Option 1 State Compliance Approach in 2030 

PM2.5 precursors: b

SO2 ............................................................................................................ 471 $21 to $47 ....................................... $19 to $43 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) ............. 6 $0.87 to $2.0 ................................... $0.78 to $1.8 

Directly emitted PM2.5 (crustal) ................................................................. 44 $0.80 to $1.8 ................................... $0.72 to $1.6 

NOX ........................................................................................................... 428 $2.9 to $6.6 ..................................... $2.6 to $6.0 

Ozone precursor: c

NOX (ozone season only) ......................................................................... 187 $1.1 to $4.6 ..................................... $1.1 to $4.6 

Total Monetized Health Co-benefits ............................................................................... $27 to $62 ....................................... $24 to $57 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ....... $57 to $93 ....................................... $55 to $87 

aAll estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as 

SO2, NOX and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of the 

range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation 

of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on a 

function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the same 

for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 

TABLE 16—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE OPTION 2 REGIONAL COMPLIANCE

APPROACH

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized health co-benefits 

(3 percent discount) 

Monetized health co-benefits 

(7 percent discount) 

Option 2 Regional Compliance Approach 2020 

PM2.5 precursors: b

SO2 ............................................................................................................ 244 $9.8 to $22 ...................................... $8.9 to $20 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) ............. 5 $0.61 to $1.4 ................................... $0.55 to $1.2 

Directly emitted PM2.5 (crustal) ................................................................. 36 $0.63 to $1.4 ................................... $0.57 to $1.3 

NOX ........................................................................................................... 268 $1.7 to $3.9 ..................................... $1.6 to $3.5 

Ozone precursor: c


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TABLE 16—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR THE OPTION 2 REGIONAL COMPLIANCE

APPROACH—Continued 

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized health co-benefits 

(3 percent discount) 

Monetized health co-benefits 

(7 percent discount) 

NOX (ozone season only) ......................................................................... 111 $0.47 to $2.0 ................................... $0.47 to $2.0 

Total Monetized Health Co-benefits ............................................................................... $13 to $31 ....................................... $12 to $28 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ....... $26 to $44 ....................................... $25 to $41 

Option 2 Regional Compliance Approach in 2025 

PM2.5 precursors: b

SO2 ............................................................................................................ 297 $13 to $29 ....................................... $12 to $26 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon) ............. 4 $0.64 to $1.4 ................................... $0.58 to $1.3 

Directly emitted PM2.5 (crustal) ................................................................. 34 $0.59 to $1.3 ................................... $0.53 to $1.2 

NOX ........................................................................................................... 309 $2.2 to $5.0 ..................................... $2.0 to $4.5 

Ozone precursor: c

NOX (ozone season only) ......................................................................... 129 $0.73 to $3.1 ................................... $0.73 to $3.1 

Total Monetized Health Co-benefits ............................................................................... $17 to $40 ....................................... $16 to $36 

Total Monetized Health Co-benefits combined with Monetized Climate Benefits d ....... $36 to $59 ....................................... $34 to $55 

aAll estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air pollution 

health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5 precursors, such as 

SO2, NOX and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of the 

range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation 

of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on a 

function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits occur in the analysis year, so they are the same 

for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate, however we emphasize the importance and value of considering the full range of SCC values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 

TABLE 17—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR OPTION 2 STATE COMPLIANCE

APPROACH

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized health co-benefits 

(3 percent discount) 

Monetized health co-benefits 

(7 percent discount) 

Option 2 State Compliance Approach in 2020 

PM2.5 precursors:b

SO2 ........................................................................................... 267 $10 to $23 ............................... $9.1 to $21 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon).5 $0.64 to $1.5 ........................... $0.58 to $1.3 

Directly emitted PM2.5 (crustal) ................................................. 38 $0.66 to $1.5 ........................... $0.60 to $1.4 

NOX ........................................................................................... 281 $1.7 to $3.8 ............................. $1.5 to $3.4 

Ozone precursor:c

NOX (ozone season only) ......................................................... 119 $0.48 to $2.1 ........................... $0.48 to $2.1 

Total Monetized Health Co-benefits .............................................................. $14 to $32 ............................... $12 to $29 

Total Monetized Health Co-benefits combined with Monetized Climate 

Benefits d.

$27 to $45 ............................... $26 to $42 

Option 2 State Compliance Approach in 2025 

PM2.5 precursors: b

SO2 ........................................................................................... 327 $14 to $30 ............................... $12 to $27 

Directly emitted PM2.5 (Elemental Carbon and Organic Carbon).5 $0.69 to $1.6 ........................... $0.63 to $1.4 

Directly emitted PM2.5 (crustal) ................................................. 38 $0.64 to $1.4 ........................... $0.58 to $1.3 

NOX ........................................................................................... 317 $2.1 to $4.7 ............................. $1.9 to $4.2 

Ozone precursor:c


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34940 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

331 Docket ID EPA–HQ–OAR–2013–0495, 

Technical Support Document: Technical Update of 

the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866, Interagency 

Working Group on Social Cost of Carbon, with 

participation by Council of Economic Advisers, 

Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department 

of Energy, Department of Transportation, 

Environmental Protection Agency, National 

Economic Council, Office of Energy and Climate 

Change, Office of Management and Budget, Office 

of Science and Technology Policy, and Department 

of Treasury (May 2013, Revised November 2013). 

Available at: http://www.whitehouse.gov/sites/

default/files/omb/assets/inforeg/technical-updatesocial-cost-of-carbon-for-regulator-impactanalysis.pdf. 

332 Docket ID EPA–HQ–OAR–2009–0472–114577, 

Technical Support Document: Social Cost of 

Carbon for Regulatory Impact Analysis Under 

Executive Order 12866, Interagency Working Group 

on Social Cost of Carbon, with participation by the 

Council of Economic Advisers, Council on 

Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, 

Department of Transportation, Environmental 

Protection Agency, National Economic Council, 

Office of Energy and Climate Change, Office of 

Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury 

(February 2010). Also available at: http://

www.whitehouse.gov/sites/default/files/omb/

inforeg/for-agencies/Social-Cost-of-Carbon-forRIA.pdf>. 

333The 2010 and 2013 TSDs present SCC in 

$2007. The estimates were adjusted to 2011$ using 

the GDP Implicit Price Deflator. Also available at: 

http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/

ECONI-2013-02-Pg3.pdf. 

TABLE 17—SUMMARY OF THE MONETIZED HEALTH CO-BENEFITS IN THE U.S. FOR OPTION 2 STATE COMPLIANCE

APPROACH—Continued 

[Billions of 2011 dollars] a

Pollutant 

National 

emission 

reductions 

(thousands of 

short tons) 

Monetized health co-benefits 

(3 percent discount) 

Monetized health co-benefits 

(7 percent discount) 

NOX (ozone season only) ......................................................... 136 $0.72 to $3.1 ........................... $0.72 to $3.1 

Total Monetized Health Co-benefits .............................................................. $18 to $41 ............................... $16 to $16 

Total Monetized Health Co-benefits combined with Monetized Climate 

Benefits d.

$36 to $60 ............................... $35 to $56 

aAll estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so estimates may not sum. It is important to 

note that the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects 

or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S. bThe monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown as a range reflecting the use of two concentration-response 

functions, with the lower end of the range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et 

al. (2012). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. cThe monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NOX

during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with 

the lower end of the range based on a function from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone 

co-benefits occur in the analysis year, so they are the same for all discount rates. dWe estimate climate benefits associated with four different values of a one ton CO2 reduction (model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 percent), which each increase over time. For the purposes of this table, we show the benefits associated with the model average at 3% discount rate; however, we emphasize the importance and value of considering the full range of SCC values. 

We provide combined climate and health estimates based on additional discount rates in the RIA. 

The EPA has used the social cost of 

carbon (SCC) estimates presented in the 

2013 Technical Support Document: 

Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (2013 SCC 

TSD) to analyze CO2 climate impacts of 

this rulemaking.331 We refer to these 

estimates, which were developed by the 

U.S. government, as ‘‘SCC estimates.’’ 

The U.S. government first published the 

SCC estimates in 2010 following an 

interagency process that included the 

EPA and other executive branch 

entities; the process used three 

integrated assessment models (IAM) to 

develop SCC estimates and selected four 

global values for use in regulatory 

analyses. The U.S. government recently 

updated these estimates using new 

versions of each integrated assessment 

model and published them in 2013. The 

2013 update did not revisit the 2010 

modeling decisions (e.g., with regard to 

the discount rate, reference case 

socioeconomic and emission scenarios 

or equilibrium climate sensitivity). 

Rather, improvements in the way 

damages are modeled are confined to 

those that have been incorporated into 

the latest versions of the models by the 

developers themselves and published in 

the peer-reviewed literature. The 2010 

SCC Technical Support Document (2010 

SCC TSD) provides a complete 

discussion of the methods used to 

develop these estimates and the 2013 

SCC TSD presents and discusses the 

updated estimates.332

The EPA and other agencies have 

sought public comment on the SCC 

estimates as part of various rulemakings. 

In addition, OMB’s Office of 

Information and Regulatory Affairs 

recently sought public comment on the 

approach used to develop the estimates. 

The comment period ended on February 

26, 2014, and OMB is reviewing the 

comments received. 

The four SCC estimates, updated in 

2013, are as follows: $13, $46, $68, and 

$137 per metric ton of CO2 emissions in 

the year 2020 (2011 dollars).333 The first 

three values are based on the average 

SCC from the three IAMs, at discount 

rates of 5, 3, and 2.5 percent, 

respectively. SCCs at several discount 

rates are included because the literature 

shows that the SCC is quite sensitive to 

assumptions about the discount rate, 

and because no consensus exists on the 

appropriate rate to use in an 

intergenerational context (where costs 

and benefits are incurred by different 

generations). The fourth value is the 

95th percentile of the SCC from all three 

models at a 3 percent discount rate. It 

is included to represent higher-thanexpected impacts from temperature 

change further out in the tails of the 

SCC distribution (representing less 

likely, but potentially catastrophic, 

outcomes). 

The 2010 SCC TSD noted a number of 

limitations to the SCC analysis, 

including the incomplete way in which 

the integrated assessment models 

capture catastrophic and noncatastrophic impacts, their incomplete 

treatment of adaptation and 


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334Fann, N., K.R. Baker and C.M. Fulcher. 2012. 

‘‘Characterizing the PM2.5-related health benefits of 

emission reductions for 17 industrial, area and 

mobile emission sectors across the U.S.’’ 

Environment International 49 41–151. 

335U.S. Environmental Protection Agency (U.S. 

EPA). 2012. Regulatory Impact Analysis for the 

Final Revisions to the National Ambient Air Quality 

Standards for Particulate Matter. Research Triangle 

Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts 

Division. (EPA document number EPA–452/R–12– 

003, December). Available at: <http://www.epa.gov/ 

pm/2012/finalria.pdf>. 

336U.S. Environmental Protection Agency (U.S. 

EPA). 2008b. Final Ozone NAAQS Regulatory 

Impact Analysis. Research Triangle Park, NC: Office 

of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and 

Cost Group Research. (EPA document number EPA– 

452/R–08–003, March). Available at: <http://

cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=194645>. 

337U.S. Environmental Protection Agency (U.S. 

EPA). 2010. Section 3: Re-analysis of the Benefits 

of Attaining Alternative Ozone Standards to 

Incorporate Current Methods. Available at <http:// 

www.epa.gov/ttnecas1/regdata/RIAs/s3- 

supplemental_analysis-updated_benefits11- 

5.09.pdf>. 

338U.S. Environmental Protection Agency. 2013. 

Technical support document: Estimating the benefit 

per ton of reducing PM2.5 precursors from 17 

sectors. Research Triangle Park, NC: Office of Air 

and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: <http://

www.epa.gov/airquality/benmap/models/Source_

Apportionment_BPT_TSD_1_31_13.pdf>. 

339 Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. 

Hughes; Y. Shi, et al. 2009. Extended Follow-up and 

Spatial Analysis of the American Cancer Society 

Study Linking Particulate Air Pollution and 

Mortality. Health Effects Institute. (HEI Research 

Report number 140). Boston, MA: Health Effects 

Institute. 

340Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 

2012. ‘‘Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard 

Six Cities Study from 1974 to 2009.’’ Environmental 

Health Perspective, 120(7), July, pp. 965–970. 

341Roman, H., et al. 2008. ‘‘Expert Judgment 

Assessment of the Mortality Impact of Changes in 

Ambient Fine Particulate Matter in the U.S.’’ 

Environmental Science & Technology, Vol. 42, No. 

7, February, pp. 2268–2274. 

342Bell, M.L., et al. 2004. ‘‘Ozone and Short-Term 

Mortality in 95 U.S. Urban Communities, 1987– 

2000.’’ Journal of the American Medical 

Association, 292(19), pp. 2372–8. 

343Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 

2005. ‘‘Ozone exposure and mortality: an empiric 

bayes metaregression analysis.’’ Epidemiology. 

16(4): p. 458–68. 

344U.S. Environmental Protection Agency. 2009. 

Integrated Science Assessment for Particulate 

Matter (Final Report). Research Triangle Park, NC: 

National Center for Environmental Assessment, 

RTP Division. (EPA document number EPA–600–R– 

08–139F, December). Available at: <http://

cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=216546>. 

technological change, uncertainty in the 

extrapolation of damages to high 

temperatures, and assumptions 

regarding risk aversion. Current 

integrated assessment models do not 

assign value to all of the important 

physical, ecological, and economic 

impacts of climate change recognized in 

the climate change literature for various 

reasons, including the inherent 

difficulties in valuing non-market 

impacts and the fact that the science 

incorporated into these models 

understandably lags behind the most 

recent research. Nonetheless, these 

estimates and the discussion of their 

limitations represent the best available 

information about the social benefits of 

CO2 emission reductions to inform the 

benefit-cost analysis. Model developers 

continually update the models to 

incorporate recent research. The new 

versions of the models used to estimate 

the values presented in this rulemaking 

offer some improvements in these areas 

identified above, although further work 

is warranted. Accordingly, the EPA and 

other parties continue to conduct 

research on modeling and valuation of 

climate impacts with the goal of 

improving these estimates. Additional 

details are provided in the SCC TSDs. 

The health co-benefits estimates 

represent the total monetized human 

health benefits for populations exposed 

to reduced PM2.5 and ozone resulting 

from emission reductions under 

illustrative compliance options for the 

proposed standards. Unlike the global 

SCC estimates, the air pollution health 

co-benefits are estimated for the 

contiguous U.S. only. We used a 

‘‘benefit-per-ton’’ approach to estimate 

the benefits of this rulemaking. To 

create the PM2.5 benefit-per-ton 

estimates, this approach uses a model to 

convert emissions of PM2.5 precursors 

into changes in ambient PM2.5 levels 

and another model to estimate the 

changes in human health effects 

associated with that change in air 

quality, which are then divided by the 

emissions in specific sectors. We 

derived national average benefit-per-ton 

estimates for the EGU sector using the 

approach published in Fann et al. 

(2012),334 and updated those estimates 

to reflect the studies and population 

data in the 2012 PM NAAQS RIA. We 

further separated the national estimates 

into regional estimates to provide 

greater spatial resolution.335 In addition, 

we generated regional benefit-per-ton 

estimates for changes in ozone 

exposure. The ozone estimates used the 

ozone information from the sector 

modeling for the EGU sector described 

in Fann et al. (2012) and the health 

impact assumptions used in the Ozone 

NAAQS RIAs.336 337 To calculate the cobenefits for the proposed standards, we 

multiplied the regional benefit-per-ton 

estimates for the EGU sector by the 

corresponding emission reductions.338

All benefit-per-ton estimates reflect the 

geographic distribution of the modeled 

emissions, which may not exactly match 

the emission reductions in this 

rulemaking, and thus they may not 

reflect the local variability in population 

density, meteorology, exposure, baseline 

health incidence rates, or other local 

factors for any specific location. More 

information regarding the derivation of 

the benefit-per-ton estimates is available 

in the RIA. 

These models assume that all fine 

particles, regardless of their chemical 

composition, are equally potent in 

causing premature mortality because the 

scientific evidence is not yet sufficient 

to allow differentiation of effect 

estimates by particle type. Even though 

we assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between 

precursors depending on the location 

and magnitude of their impact on PM2.5

levels, which drive population 

exposure. 

It is important to note that the 

magnitude of the PM2.5 and ozone cobenefits is largely driven by the 

concentration response functions for 

premature mortality and the value of a 

statistical life used to value reductions 

in premature mortality. For PM2.5, we 

cite two key empirical studies, one 

based on the American Cancer Society 

cohort study 339 and the extended Six 

Cities cohort study.340 We present the 

PM2.5 co-benefits results as a range 

based on the concentration-response 

functions from these two epidemiology 

studies, but this range does not capture 

the full range of uncertainty inherent in 

the co-benefits estimates. In the RIA for 

this rule, which is available in the 

docket, we also include PM2.5 cobenefits estimates derived from expert 

judgments (Roman et al., 2008) 341 as a 

characterization of uncertainty 

regarding the PM2.5-mortality 

relationship. For the ozone co-benefits, 

we present the results as a range 

reflecting the use of several different 

concentration-response functions for 

mortality, with the lower end of the 

range based on a function from Bell et 

al. (2004) 342 and the upper end based 

on a function from Levy et al. (2005).343

Similar to PM2.5, the range of ozone cobenefits does not capture the full range 

of inherent uncertainty. 

In this analysis, the EPA assumes that 

the health impact function for fine 

particles is without a threshold. This is 

based on the conclusions of EPA’s 

Integrated Science Assessment for 

Particulate Matter,344 which evaluated 

the substantial body of published 

scientific literature, reflecting thousands 

of epidemiology, toxicology, and 

clinical studies that documents the 

association between elevated PM2.5


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345 In addition, site-specific emission reductions 

will depend upon how states implement the 

guidelines. 

concentrations and adverse health 

effects, including increased premature 

mortality. This assessment, which was 

twice reviewed by the EPA’s 

independent Science Advisory Board, 

concluded that the scientific literature 

consistently finds that a no-threshold 

model most adequately portrays the PMmortality concentration-response 

relationship. 

In general, we are more confident in 

the magnitude of the risks we estimate 

from simulated PM2.5 concentrations 

that coincide with the bulk of the 

observed PM concentrations in the 

epidemiological studies that are used to 

estimate the benefits. Likewise, we are 

less confident in the risk we estimate 

from simulated PM2.5 concentrations 

that fall below the bulk of the observed 

data in these studies. 

For this analysis, policy-specific air 

quality data are not available,345 and 

thus, we are unable to estimate the 

percentage of premature mortality 

associated with this specific rule’s 

emission reductions at each PM2.5 level. 

As a surrogate measure of mortality 

impacts, we provide the percentage of 

the population exposed above the 

lowest measured PM2.5 level (LML) in 

each of the studies from which we 

obtained concentration-response 

functions for PM2.5 mortality, using the 

estimates of PM2.5 from the source 

apportionment modeling used to 

calculate the benefit-per-ton estimates 

for the EGU sector. Using the Krewski 

et al. (2009) study, 93 percent of the 

population is exposed to annual mean 

PM2.5 levels at or above the LML of 5.8 

micrograms per cubic meter (mg/m3). 

Using the Lepeule et al. (2012) study, 67 

percent of the population is exposed 

above the LML of 8 mg/m3. It is 

important to note that baseline exposure 

is only one parameter in the health 

impact function, along with baseline 

incidence rates, population, and change 

in air quality. Therefore, caution is 

warranted when interpreting the LML 

assessment for this rule because these 

results are not consistent with results 

from rules that had air quality modeling. 

Every benefit analysis examining the 

potential effects of a change in 

environmental protection requirements 

is limited, to some extent, by data gaps, 

model capabilities (such as geographic 

coverage) and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Despite these uncertainties, 

we believe the air quality co-benefit 

analysis for this rule provides a 

reasonable indication of the expected 

health benefits of the air pollution 

emission reductions for the illustrative 

compliance options for the proposed 

standards under a set of reasonable 

assumptions. This analysis does not 

include the type of detailed uncertainty 

assessment found in the 2012 PM2.5

National Ambient Air Quality Standard 

(NAAQS) RIA (U.S. EPA, 2012) because 

we lack the necessary air quality input 

and monitoring data to conduct a 

complete benefits assessment. In 

addition, using a benefit-per-ton 

approach adds another important source 

of uncertainty to the benefits estimates. 

The 2012 PM2.5 NAAQS benefits 

analysis provides an indication of the 

sensitivity of our results to various 

assumptions. 

We note that the monetized cobenefits estimates shown here do not 

include several important benefit 

categories, including exposure to SO2, 

NOX, and hazardous air pollutants (e.g., 

mercury and hydrogen chloride), as well 

as ecosystem effects and visibility 

impairment. Although we do not have 

sufficient information or modeling 

available to provide monetized 

estimates for this rule, we include a 

qualitative assessment of these 

unquantified benefits in the RIA for 

these proposed amendments. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rule, which is available in the 

rulemaking docket. 

XI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

Under Section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

state, local, or tribal governments or 

communities. The $100 million 

threshold can be triggered by either 

costs or benefits, or a combination of 

them. Accordingly, the EPA submitted 

this action to OMB for review under 

Executive Orders 12866 and 13563 (76 

FR 3821, January 21, 2011), and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

The EPA also prepared an analysis of 

the potential costs and benefits 

associated with this action. This 

analysis is contained in the RIA for this 

proposed rule. A copy of the analysis is 

available in the docket for this action. 

Consistent with EO 12866 and EO 

13563, the EPA estimated the costs and 

benefits for illustrative compliance 

approaches of implementing the 

proposed guidelines. This proposal sets 

goals to reduce CO2 emissions from the 

electric power industry. Actions taken 

to comply with the proposed guidelines 

will also reduce the emissions of 

directly emitted PM2.5, sulfur dioxide 

(SO2) and nitrogen oxides (NOX). The 

benefits associated with these PM, SO2

and NOX reductions are referred to as 

co-benefits, as these reductions are not 

the primary objective of this rule. 

The EPA has used the social cost of 

carbon estimates presented in the 2013 

Technical Support Document: 

Technical Update of the Social Cost of 

Carbon for Regulatory Impact Analysis 

Under Executive Order 12866 (2013 SCC 

TSD) to analyze CO2 climate impacts of 

this rulemaking. We refer to these 

estimates, which were developed by the 

U.S. government, as ‘‘SCC estimates.’’ 

The SCC is an estimate of the monetary 

value of impacts associated with a 

marginal change in CO2 emissions in a 

given year. The four SCC estimates are 

associated with different discount rates 

(model average at 2.5 percent discount 

rate, 3 percent, and 5 percent; 95th 

percentile at 3 percent), and each 

increases over time. In this summary, 

the EPA provides the estimate of climate 

benefits associated with the SCC value 

deemed to be central in the SCC TSD: 

The model average at 3% discount rate. 

For the regional compliance approach, 

the EPA estimates that in 2020 this 

Option 1 proposal will yield monetized 

climate benefits (in 2011$) of 

approximately $17 billion (3 percent 

model average). The air pollution health 

co-benefits in 2020 are estimated to be 

$16 billion to $37 billion (2011$) for a 

3 percent discount rate and $15 billion 

to $34 billion (2011$) for a 7 percent 

discount rate. The annual, illustrative 

compliance costs estimated by IPM and 

inclusive of demand side energy 

efficiency program and participant costs 

and MRR costs, are approximately $5.5 

billion (2011$) in 2020. The quantified 

net benefits (the difference between 

monetized benefits and costs) in 2020 

are estimated to be $28 billion to $49 

billion assuming a regional compliance 

approach (2011$) using a 3 percent 

discount rate (model average). This 

range of net benefits is estimated to be 

$27 billion to $50 billion assuming a 

state compliance approach (2011$) 


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using a 3 percent discount rate (model 

average). Table 18 shows the climate 

benefits, health co-benefits, cost and net 

benefits for Option 1 in 2020 for state 

and regional compliance approaches. 

Table 19 shows similar estimates for 

2030. 

For Option 1 in 2030 assuming a 

regional compliance approach, the EPA 

estimates this proposal will yield 

monetized climate benefits (in 2011$) of 

approximately $30 billion (3 percent, 

model average). The air pollution health 

co-benefits in 2030 are estimated to be 

$25 billion to $59 billion (2011$) for a 

3 percent discount rate and $23 billion 

to $54 billion (2011$) for a 7 percent 

discount rate. The annual illustrative 

compliance costs estimated using IPM, 

inclusive of a demand-side energy 

efficiency program and participant costs 

and MRR costs, are approximately $7.3 

billion (2011$) in 2030. The quantified 

net benefits (the difference between 

monetized benefits and costs) in 2030 

are estimated to be $48 billion to $82 

billion (2011$) using a 3 percent 

discount rate (model average). The EPA 

estimates that this proposal will yield 

monetized climate benefits (in 2011$) of 

approximately $31 billion (3 percent, 

model average) for Option 1 state 

compliance approach in 2030. The air 

pollution health co-benefits in 2030 are 

estimated to be $27 billion to $62 billion 

(2011$) for a 3 percent discount rate and 

$24 billion to $56 billion (2011$) for a 

7 percent discount rate. The annual 

illustrative compliance costs estimated 

using IPM, inclusive of demand side 

energy efficiency program and 

participant costs and MRR costs, are 

approximately $8.8 billion (2011$) in 

2030. The quantified net benefits (the 

difference between monetized benefits 

and costs) in 2030 are estimated to be 

$49 billion to $84 billion (2011$) using 

a 3 percent discount rate (model 

average) assuming a state compliance 

approach. Based upon the foregoing 

discussion, it remains clear that the 

benefits of the proposal Option 1 are 

substantial and far exceed the costs. 

TABLE 18—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS AND NET BENEFITS FOR PROPOSED OPTION 1 

IN 2020 a

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Option 1 Regional Compliance Approach 

Climate benefits b ........................................................................................................... $17. 

Air pollution health co-benefits c .................................................................................... $16 to $37 .................................................................... $15 to $34 

Total Compliance Costs d ............................................................................................... $5.5 ............................................................................... $5.5 

Net Monetized Benefits e ................................................................................................ $28 to $49 .................................................................... $26 to $45 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

1.3 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

Option 1 State Compliance Approach 

Climate benefits b ........................................................................................................... $18. 

Air pollution health co-benefits c .................................................................................... $17 to $40 .................................................................... $15 to $36 

Total Compliance Costs d ............................................................................................... $7.5 ............................................................................... $7.5 

Net Monetized Benefits e ................................................................................................ $27 to $50 .................................................................... $26 to $46 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

1.5 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

aAll estimates are for 2020, and are rounded to two significant figures, so figures may not sum. 

bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC 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 SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 

percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent 

in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates. 

TABLE 19—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 1 

IN 2030 a

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Option 1 Regional Compliance Approach 

Climate benefits b .......................................................................................... $30. 

Air pollution health co-benefits c ................................................................... $25 to $59 ......................................................... $23 to $54 

Total Compliance Costs d ............................................................................. $7.3 ................................................................... $7.3 

Net Monetized Benefits e .............................................................................. $48 to $82 ......................................................... $46 to $77 


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34944 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

TABLE 19—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 1 

IN 2030 a—Continued 

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Non-monetized Benefits ............................................................................... Direct exposure to SO2 and NO2. 

1.7 tons of Hg and 580 tons of HCl. 

Ecosystem Effects. 

Visibility impairment. 

Option 1 State Compliance Approach 

Climate benefits b .......................................................................................... $31. 

Air pollution health co-benefits c ................................................................... $27 to $62 ......................................................... $24 to $56 

Total Compliance Costs d ............................................................................. $8.8 ................................................................... $8.8 

Net Monetized Benefits e .............................................................................. $49 to $84 ......................................................... $46 to $79 

Non-monetized Benefits ............................................................................... Direct exposure to SO2 and NO2. 

2.1 tons of Hg and 590 tons of HCl. 

Ecosystem Effects. 

Visibility impairment. 

aAll estimates are for 2030, and are rounded to two significant figures, so figures may not sum. 

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

non-CO2 GHG emissions. Also, different discount rates are applied to SCC 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 SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted 

PM2.5, SO2 and NOX. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine 

particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and 

a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model 

average). The RIA includes combined climate and health estimates based on these additional discount rates. 

The estimated costs and benefits for 

the regulatory alternative—Option 2 

regional and state compliance 

approaches are shown in Tables 20 and 

21. As these tables reflect, net benefits 

in 2020 are estimated to be $22 to $40 

billion (3 percent discount rate) and $21 

to $37 billion (7 percent discount rate) 

for Option 2 assuming regional 

compliance. These Option 2 net benefit 

estimates become $22 to $40 billion (3 

percent discount rate) and $20 to $37 

billion (7 percent discount rate) with the 

state compliance approach. In 2025, net 

benefits are estimated to be $31 billion 

to $54 billion (3 percent discount rate) 

and $29 billion to $50 billion (7 percent 

discount rate) assuming a regional 

compliance approach and $31 billion to 

$55 billion (3 percent discount rate) and 

$29 billion to $51 billion (7 percent 

discount rate) assuming a state 

compliance approach. 

The EPA could not monetize 

important benefits of proposed Option 1 

and regulatory alternative Option 2. 

Unquantified benefits include climate 

benefits from reducing emissions of 

non-CO2 greenhouse gases and cobenefits from reducing exposure to SO2, 

NOX, and hazardous air pollutants (e.g., 

mercury and hydrogen chloride), as well 

as ecosystem effects and visibility 

impairment. 

TABLE 20—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 2 

IN 2020 a 

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Option 2 Regional Compliance Approach 

Climate benefits b ........................................................................................................... $13. 

Air pollution health co-benefits c .................................................................................... $13 to $31 .................................................................... $12 to $28 

Total Compliance Costs d ............................................................................................... $4.3 ............................................................................... $4.3 

Net Monetized Benefits e ................................................................................................ $22 to $40 .................................................................... $21 to $37 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

0.9 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 


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TABLE 20—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 2 

IN 2020 a—Continued 

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Option 2 State Compliance Approach 

Climate benefits b ........................................................................................................... $14. 

Air pollution health co-benefits c .................................................................................... $14 to $32 .................................................................... $12 to $29 

Total Compliance Costs d ............................................................................................... $5.5 ............................................................................... $5.5 

Net Monetized Benefits e ................................................................................................ $22 to $40 .................................................................... $20 to $37 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

1.2 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

aAll estimates are for 2020, and are rounded to two significant figures, so figures may not sum. 

bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC 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 SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 

percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent 

in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates. 

TABLE 21—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS FOR PROPOSED OPTION 2 

IN 2025 a

[Billions of 2011$] 

3% Discount rate 7% Discount rate 

Option 2 Regional Compliance Approach 

Climate benefits b ........................................................................................................... $18. 

Air pollution health co-benefits c .................................................................................... $17 to $40 .................................................................... $16 to $36 

Total Compliance Costs d ............................................................................................... $4.5 ............................................................................... $4.5 

Net Monetized Benefits e ................................................................................................ $31 to $54 .................................................................... $29 to $50 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

1.3 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

Option 2 State Compliance Approach 

Climate benefits b ........................................................................................................... $19. 

Air pollution health co-benefits c .................................................................................... $18 to $41 .................................................................... $16 to $37 

Total Compliance Costs d ............................................................................................... $5.5 ............................................................................... $5.5 

Net Monetized Benefits e ................................................................................................ $31 to $55 .................................................................... $29 to $51 

Non-monetized Benefits ................................................................................................. Direct exposure to SO2 and NO2. 

1.7 tons of Hg. 

Ecosystem Effects. 

Visibility impairment. 

aAll estimates are for 2025, and are rounded to two significant figures, so figures may not sum. 

bThe climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG emissions. Also, different discount rates are applied to SCC 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 SCC values. As shown in the RIA, climate benefits are also estimated using the other three SCC estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SCC estimates are year-specific and increase over time. cThe air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOX. The 

range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 

percent of total monetized co-benefits from PM2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent 

in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. dTotal costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the proposed option and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping and reporting costs and demand side energy efficiency program and participant costs. eThe estimates of net benefits in this summary table are calculated using the global social cost of carbon at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on these additional discount rates. 

The analysis done in support of this 

proposal shows that the emission 

reductions, benefits, and costs for the 

illustrative compliance approaches for 

the proposed Option 1 (and regulatory 

alternative Option 2) are larger if states 

choose to comply on an individual 

basis, compared to the illustrative 

regional compliance approach. The 

regional approach allows for more 

flexibility across states, which results in 

slightly fewer emission reductions and 


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lower overall costs. Net benefits (the 

difference between benefits and costs) 

are roughly equivalent under the 

regional and state compliance 

approaches. 

In evaluating the impacts of the 

proposed guidelines, we analyzed a 

number of uncertainties, for example 

evaluating different potential spatial 

approaches to state compliance (i.e., 

state and regional) and in the estimated 

benefits of reducing carbon dioxide and 

other air pollutants. For a further 

discussion of key evaluations of 

uncertainty in the regulatory analyses 

for this proposed rulemaking, see the 

RIA included in the docket. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by the EPA has been 

assigned the EPA ICR number 2503.01. 

The information collection 

requirements are based on the 

recordkeeping and reporting burden 

associated with developing, 

implementing, and enforcing a state 

plan to limit CO2 emissions from 

existing sources in the power sector. 

These recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). 

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to agency 

policies set forth in 40 CFR part 2, 

subpart B. 

The annual burden for this collection 

of information for the states (averaged 

over the first 3 years following 

promulgation of this proposed action) is 

estimated to be a range of 316,217 hours 

at a total annual labor cost of 

$22,381,044, to 633,001 hours at a total 

annual labor cost of $44,802,243. The 

lower bound estimate reflects the 

assumption that some states already 

have energy efficiency and renewable 

energy programs in place. The higher 

bound estimate reflects the assumption 

that no states have energy efficiency and 

renewable energy programs in place. 

The total annual burden for the federal 

government (averaged over the first 3 

years following promulgation of this 

proposed action) is estimated to be 

53,300 hours at a total annual labor cost 

of $2,958,005. Burden means the total 

time, effort, or financial resources 

expended by persons to generate, 

maintain, retain, or disclose or provide 

information to or for a federal agency. 

This includes the time needed to review 

instructions; develop, acquire, install, 

and utilize technology and systems for 

the purposes of collecting, validating, 

and verifying information, processing 

and maintaining information, and 

disclosing and providing information; 

adjust the existing ways to comply with 

any previously applicable instructions 

and requirements; train personnel to be 

able to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations are 

listed in 40 CFR part 9 and 48 CFR 

chapter 15. 

To comment on the agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID Number EPA–HQ–OAR–2013–0602. 

Submit any comments related to the ICR 

to the EPA and to OMB. See the 

ADDRESSES section at the beginning of 

this notice for where to submit 

comments to the EPA. Send comments 

to OMB at the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, 725 17th 

Street, NW., Washington, DC 20503, 

Attention: Desk Office for the EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after June 18, 2014, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by July 18, 2014. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, small 

entity is defined as: 

(1) A small business that is defined by 

the SBA’s regulations at 13 CFR 121.201 

(for the electric power generation 

industry, the small business size 

standard is an ultimate parent entity 

with less than 750 employees. The 

NAICS codes for the affected industry 

are in Table 22 below); 

(2) A small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and 

(3) A small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

TABLE 22—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Category NAICS 

Code Examples of potentially regulated entities a

Industry .......................................................................................................... 221112 Fossil fuel electric power generating units. 

State/Local Government ................................................................................ 221112 b Fossil fuel electric power generating units owned by 

municipalities. 

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines). bState or local government-owned and operated establishments are classified according to the activity in which they are engaged.

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The proposed rule will not impose 

any requirements on small entities. 

Specifically, emission guidelines 


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established under CAA section 111(d) 

do not impose any requirements on 

regulated entities and, thus, will not 

have a significant economic impact 

upon a substantial number of small 

entities. After emission guidelines are 

promulgated, states establish standards 

on existing sources, and it is those state 

requirements that could potentially 

impact small entities. Our analysis here 

is consistent with the analysis of the 

analogous situation arising when the 

EPA establishes NAAQS, which do not 

impose any requirements on regulated 

entities. As here, any impact of a 

NAAQS on small entities would only 

arise when states take subsequent action 

to maintain and/or achieve the NAAQS 

through their state implementation 

plans. See American Trucking Assoc. v. 

EPA, 175 F.3d 1029, 1043–45 (D.C. Cir. 

1999) (NAAQS do not have significant 

impacts upon small entities because 

NAAQS themselves impose no 

regulations upon small entities). 

Nevertheless, the EPA is aware that 

there is substantial interest in the 

proposed rule among small entities 

(municipal and rural electric 

cooperatives). As detailed in Section 

III.A of this preamble, the EPA has 

conducted an unprecedented amount of 

stakeholder outreach on setting 

emission guidelines for existing EGUs. 

While formulating the provisions of the 

proposed rule, the EPA considered the 

input provided over the course of the 

stakeholder outreach. Section III.B of 

this preamble describes the key 

messages from stakeholders. In addition, 

as described in the RFA section of the 

preamble to the proposed standards of 

performance for GHG emissions from 

new EGUs (79 FR 1499–1500, January 8, 

2014), the EPA conducted outreach to 

representatives of small entities while 

formulating the provisions of the 

proposed standards. Although only new 

EGUs would be affected by those 

proposed standards, the outreach 

regarded planned actions for new and 

existing sources. We invite comments 

on all aspects of the proposal and its 

impacts, including potential impacts on 

small entities. 

D. Unfunded Mandates Reform Act 

This proposed action does not contain 

a federal mandate that may result in 

expenditures of $100 million or more 

for state, local, and tribal governments, 

in the aggregate, or the private sector in 

any one year. Specifically, the emission 

guidelines proposed under CAA section 

111(d) do not impose any direct 

compliance requirements on regulated 

entities, apart from the requirement for 

states to develop state plans. The 

burden for states to develop state plans 

in the 3-year period following 

promulgation of the rule was estimated 

and is listed in Section IX B., above, but 

this burden is estimated to be below 

$100 million in any one year. Thus, this 

proposed rule is not subject to the 

requirements of section 202 or section 

205 of the Unfunded Mandates Reform 

Act (UMRA). 

This proposed rule is also not subject 

to the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

In light of the interest among 

governmental entities, the EPA initiated 

consultations with governmental 

entities while formulating the 

provisions of the proposed standards for 

new EGUs. Although only new EGUs 

would be affected by those proposed 

standards, the outreach regarded 

planned actions for new and existing 

sources. As described in the UMRA 

discussion in the preamble to the 

proposed standards of performance for 

GHG emissions from new EGUs (79 FR 

1500–1501, January 8, 2014), the EPA 

consulted with the following 10 

national organizations representing state 

and local elected officials: (1) National 

Governors Association; (2) National 

Conference of State Legislatures, (3) 

Council of State Governments, (4) 

National League of Cities, (5) U.S. 

Conference of Mayors, (6) National 

Association of Counties, (7) 

International City/County Management 

Association, 8) National Association of 

Towns and Townships, (9) County 

Executives of America, and 10) 

Environmental Council of States. On 

February 26, 2014, the EPA re-engaged 

with those governmental entities to 

provide a pre-proposal update on the 

emission guidelines for existing EGUs 

and emission standards for modified 

and reconstructed EGUs. 

While formulating the provisions of 

these proposed emission guidelines, the 

EPA also considered the input provided 

over the course of the extensive 

stakeholder outreach conducted by the 

EPA (see Sections III.A. and III.B. of this 

preamble). 

E. Executive Order 13132, Federalism 

Under Executive Order 13132, the 

EPA may not issue an action that has 

federalism implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by state and 

local governments, or the EPA consults 

with state and local officials early in the 

process of developing the proposed 

action. 

The EPA has concluded that this 

action may have federalism 

implications, because it may impose 

substantial direct compliance costs on 

state or local governments, and the 

federal government will not provide the 

funds necessary to pay those costs. As 

discussed in the Supporting Statement 

found in the docket for this rulemaking, 

the development of state plans will 

entail many hours of staff time to 

develop and coordinate programs for 

compliance with the proposed rule, as 

well as time to work with state 

legislatures as appropriate, and develop 

a plan submittal. 

The EPA consulted with state and 

local officials early in the process of 

developing the proposed action to 

permit them to have meaningful and 

timely input into its development. As 

described in the Federalism discussion 

in the preamble to the proposed 

standards of performance for GHG 

emissions from new EGUs (79 FR 1501, 

January 8, 2014), the EPA consulted 

with state and local officials in the 

process of developing the proposed 

standards for newly constructed EGUs. 

This outreach regarded planned actions 

for new, reconstructed, modified and 

existing sources. The EPA invited the 

following 10 national organizations 

representing state and local elected 

officials to a meeting on April 12, 2011, 

in Washington DC: (1) National 

Governors Association; (2) National 

Conference of State Legislatures, (3) 

Council of State Governments, (4) 

National League of Cities, (5) U.S. 

Conference of Mayors, (6) National 

Association of Counties, (7) 

International City/County Management 

Association, (8) National Association of 

Towns and Townships, (9) County 

Executives of America, and (10) 

Environmental Council of States. These 

10 organizations representing elected 

state and local officials have been 

identified by the EPA as the ‘‘Big 10’’ 

organizations appropriate to contact for 

purpose of consultation with elected 

officials. On February 26, 2014, the EPA 

re-engaged with those governmental 

entities to provide a pre-proposal 

update on the emission guidelines for 

existing EGUs and emission standards 

for modified and reconstructed EGUs. In 

addition, extensive stakeholder outreach 

conducted by the EPA allowed state 

leaders, including governors, 

environmental commissioners, energy 

officers, public utility commissioners, 

and air directors, opportunities to 

engage with EPA officials and provide 

input regarding reducing carbon 

pollution from power plants. 

A detailed Federalism Summary 

Impact Statement (FSIS) describing the 


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346The EPA is aware of at least four affected 

EGUs located in Indian country: Two on Navajo 

lands, the Navajo Generating Station and the Four 

Corners Generating Station; one on Ute lands, the 

Bonanza Generating Station; and one on Fort 

Mojave lands, the South Point Energy Center. The 

affected EGUs at the first three plants are coal-fired 

EGUs. The fourth affected EGU is an NGCC facility. 

most pressing issues raised in preproposal and post-proposal comments 

will be forthcoming with the final rule, 

as required by section 6(b) of Executive 

Order 13132. In the spirit of Executive 

Order 13132, and consistent with the 

EPA’s policy to promote 

communications between the EPA and 

state and local governments, the EPA 

specifically solicits comment on this 

proposed action from State and local 

officials. 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It would not impose substantial 

direct compliance costs on tribal 

governments that have affected EGUs 

located in their area of Indian country. 

Tribes are not required to, but may, 

develop or adopt CAA programs. Tribes 

are not required to develop plans to 

implement the guidelines under CAA 

section 111(d) for affected EGUs. To the 

extent that a tribal government seeks 

and attains treatment in a manner 

similar to a state (TAS) status for that 

purpose and is delegated authority for 

air quality planning purposes, these 

proposed emission guidelines would 

require that planning requirements be 

met and emission management 

implementation plans be executed by 

the tribes. The EPA is aware of three 

coal-fired EGUs and one natural gasfired EGU located in Indian country but 

is not aware of any affected EGUs that 

are owned or operated by tribal entities. 

The EPA notes that this proposal does 

not directly impose specific 

requirements on EGU sources, including 

those located in Indian country, such as 

the three coal-fired EGUs and one 

natural gas-fired EGU, but provides 

guidance to any tribe with delegated 

authority to address CO2 emissions from 

EGU sources found subject to section 

111(d) of the CAA. Thus, Executive 

Order 13175 does not apply to this 

action. 

The EPA conducted outreach to tribal 

environmental staff and offered 

consultation with tribal officials in 

developing this action. Because the EPA 

is aware of tribal interest in this 

proposed rule, prior to the April 13, 

2012 proposal (77 FR 22392–22441), the 

EPA offered consultation with tribal 

officials early in the process of 

developing the proposed regulation to 

permit them to have meaningful and 

timely input into its development. The 

EPA’s consultation regarded planned 

actions for new and existing sources. In 

addition, on April 15, 2014, prior to 

proposal, the EPA met with Navajo 

Energy Development Group officials. 

For this proposed action for existing 

EGUs, a tribe that has one or more 

affected EGUs located in its area of 

Indian country 346 would have the 

opportunity, but not the obligation, to 

establish a CO2 performance standard 

and a CAA section 111(d) plan for its 

area of Indian country. 

Consultation letters were sent to 584 

tribal leaders. The letters provided 

information regarding the EPA’s 

development of both the NSPS and 

emission guidelines for fossil fuel-fired 

EGUs and offered consultation. No 

tribes have requested consultation. 

Tribes were invited to participate in the 

national informational webinar held 

August 27, 2013. In addition, a 

consultation/outreach meeting was held 

on September 9, 2013, with tribal 

representatives from some of the 584 

tribes. The EPA also met with tribal 

environmental staff via National Tribal 

Air Association teleconferences on July 

25, 2013, and December 19, 2013. In 

those teleconferences, the EPA provided 

background information on the GHG 

emission guidelines to be developed 

and a summary of issues being explored 

by the agency. Tribes have expressed 

varied points of view. Some tribes 

raised concerns about the impacts of the 

regulations on EGUs and the subsequent 

impact on jobs and revenue for their 

tribes. Other tribes expressed concern 

about the impact the regulations would 

have on the cost of water to their 

communities as a result of increased 

costs to the EGU that provide energy to 

transport the water to the tribes. Other 

tribes raised concerns about the impacts 

of climate change on their communities, 

resources, life ways and hunting and 

treaty rights. The tribes were also 

interested in the scope of the guidelines 

being considered by the agency (e.g., 

over what time period, relationship to 

state and multi-state plans) and how 

tribes will participate in these planning 

activities. In addition, the EPA held a 

series of listening sessions prior to 

development of this proposed action. In 

2013, tribes participated in a session 

with the state agencies, as well as a 

separate session with tribes. 

During the public comment period for 

this proposal, the EPA will hold 

meetings with tribal environmental staff 

to inform them of the content of this 

proposal, as well as offer further 

consultation with tribal elected officials 

where it is appropriate. We specifically 

solicit comment from tribal officials on 

this proposed rule. 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the Order has the potential to influence 

the regulation. This action is not subject 

to EO 13045 because it does not involve 

decisions on environmental health or 

safety risks that may disproportionately 

affect children. The EPA believes that 

the CO2 emission reductions resulting 

from implementation of the proposed 

guidelines, as well as substantial ozone 

and PM2.5 emission reductions as a cobenefit, would further improve 

children’s health. 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355; 

May 22, 2001) requires the EPA to 

prepare and submit a Statement of 

Energy Effects to the Administrator of 

the Office of Information and Regulatory 

Affairs, OMB, for actions identified as 

‘‘significant energy actions.’’ This 

action, which is a significant regulatory 

action under EO 12866, is likely to have 

a significant effect on the supply, 

distribution, or use of energy. We have 

prepared a Statement of Energy Effects 

for this action as follows. We estimate 

a 4 to 7 percent increase in retail 

electricity prices, on average, across the 

contiguous U.S. in 2020, and a 16 to 22 

percent reduction in coal-fired 

electricity generation as a result of this 

rule. The EPA projects that electric 

power sector delivered natural gas 

prices will increase by about 8 to 12 

percent in 2020. For more information 

on the estimated energy effects, please 

refer to the economic impact analysis 

for this proposal. The analysis is 

available in the RIA, which is in the 

public docket. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 104–113; 

15 U.S.C. 272 note) directs the EPA to 

use Voluntary Census Standards (VCS) 

in its regulatory and procurement 

activities unless to do so would be 

inconsistent with applicable law or 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34949 

347 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66,496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

348 ‘‘National Ambient Air Quality Standards for 

Particulate Matter, Final Rule,’’ 78 FR 3086 (Jan. 15, 

2013). 

349U.S. Environmental Protection Agency (U.S. 

EPA). 2009. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA–600–R–08– 

139F. National Center for Environmental 

Assessment—RTP Division. December. Available on 

the Internet at <http://cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=216546>. 

otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, 

business practices) developed or 

adopted by one or more voluntary 

consensus bodies. The NTTAA directs 

the EPA to provide Congress, through 

annual reports to OMB, with 

explanations when an agency does not 

use available and applicable VCS. This 

proposed rulemaking does not involve 

technical standards. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and 

specifically invites the public to identify 

potentially-applicable VCS and to 

explain why such standards should be 

used in this action. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the U.S. 

Section II.A of this preamble 

summarizes the public health and 

welfare impacts from GHG emissions 

that were detailed in the 2009 

Endangerment Finding under CAA 

section 202(a)(1).347 As part of the 

Endangerment Finding, the 

Administrator considered climate 

change risks to minority or low-income 

populations, finding that certain parts of 

the population may be especially 

vulnerable based on their 

circumstances. These include the poor, 

the elderly, the very young, those 

already in poor health, the disabled, 

those living alone, and/or indigenous 

populations dependent on one or a few 

resources. The Administrator placed 

weight on the fact that certain groups, 

including children, the elderly, and the 

poor, are most vulnerable to climaterelated health effects. 

Strong scientific evidence that the 

potential impacts of climate change 

raise environmental justice issues is 

found in the major assessment reports 

by the U.S. Global Change Research 

Program (USGCRP), the 

Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC) of the National 

Academies, summarized in the record 

for the Endangerment Finding. Their 

conclusions include that poor 

communities can be especially 

vulnerable to climate change impacts 

because they tend to have more limited 

adaptive capacities and are more 

dependent on climate-sensitive 

resources such as local water and food 

supplies. In addition, Native American 

tribal communities possess unique 

vulnerabilities to climate change, 

particularly those on established 

reservations that are restricted to 

reservation boundaries and therefore 

have limited relocation options. Tribal 

communities whose health, economic 

well-being, and cultural traditions 

depend upon the natural environment 

will likely be affected by the 

degradation of ecosystem goods and 

services associated with climate change. 

Southwest native cultures are especially 

vulnerable to water quality and 

availability impacts. Native Alaskan 

communities are likely to experience 

disruptive impacts, including shifts in 

the range or abundance of wild species 

crucial to their livelihoods and wellbeing. The most recent assessments 

continue to strengthen scientific 

understanding of climate change risks to 

minority and low-income populations. 

This proposed rule would limit GHG 

emissions by establishing CO2 emission 

guidelines for existing fossil fuel-fired 

EGUs. In addition to reducing CO2

emissions, implementing the proposed 

rule would reduce other emissions from 

EGUs that become dispatched less 

frequently due to their relatively low 

energy efficiency. These emission 

reductions will include SO2 and NOx, 

which form ambient PM2.5 and ozone in 

the atmosphere, and hazardous air 

pollutants (HAP), such as mercury and 

hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,348

the EPA identified persons with lower 

socioeconomic status as an at-risk 

population for experiencing adverse 

health effects related to PM exposures. 

Persons with lower socioeconomic 

status have been generally found to have 

a higher prevalence of pre-existing 

diseases, limited access to medical 

treatment, and increased nutritional 

deficiencies, which can increase this 

population’s risk to PM-related and 

ozone-related effects.349 Therefore, in 

areas where this rulemaking reduces 

exposure to PM2.5, ozone, and 

methylmercury, persons with low 

socioeconomic status would also 

benefit. The RIA for this rulemaking, 

included in the docket for this 

rulemaking, provides additional 

information regarding the health and 

ecosystem effects associated with these 

emission reductions. 

While there will be many locations 

with improved air quality for PM2.5, 

ozone, and HAP, there may also be 

EGUs whose emissions of one or more 

of these pollutants or their precursors 

increase as a result of the proposed 

emission guidelines for existing fossil 

fuel-fired EGUs. This may occur at 

EGUs that become dispatched more 

intensively than in the past because 

they become more energy efficient. The 

EPA has considered the potential for 

such increases and the environmental 

justice implications of such increases. 

As we noted in the NSR discussion in 

this preamble, as part of a state’s CAA 

section 111(d) plan, the state may 

require an affected EGU to undertake a 

physical or operational changes to 

improve the unit’s efficiency that result 

in an increase in the unit’s dispatch and 

an increase in the unit’s annual 

emissions of GHGs and/or other 

regulated pollutants. A state can take 

steps to avoid increased utilization of 

particular EGUs and thus avoid any 

significant increases in emissions 

including emissions of other regulated 

pollutants whose environmental effects 

would be more localized around the 

affected EGU. To the extent that states 

take this path, there would be no new 

environmental justice concerns in the 

areas near such EGUs. For any EGUs 

that make modifications that do trigger 

NSR permitting, the applicable local, 

state, or federal permitting program will 

ensure that there are no new NAAQS 

violations and that no existing NAAQS 

violations are made worse. For those 

EGUs in a permitting situation for 

which the EPA is the permit reviewing 

authority, the EPA will consider 

environmental justice issues as required 

by Executive Order 12898. 

In addition to some EGUs possibly 

being required by a state to make 

modifications for increased energy 

efficiency, another effect of the 

proposed CO2 emission guidelines for 

existing fossil fuel-fired EGUs would be 


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350 65 FR 79831. 

increased utilization of other, 

unmodified EGUs with relatively low 

GHG emissions per unit of electrical 

output, in particular high efficiency gasfired EGUs. Because such EGUs would 

not have been modified physically nor 

changed their method of operation, they 

would not be subject to review in the 

NSR permitting program. Such plants 

would have more hours in the year in 

which they operate and emit pollutants, 

including pollutants whose 

environmental effects if any would be 

localized rather than global as is the 

case with GHG emissions. Changes in 

utilization already occur now as 

demands for and sources of electrical 

energy evolve, but the proposed CO2

emission guidelines for existing fossil 

fuel-fired EGUs can be expected to 

cause more such changes. Because gasfired EGUs emit essentially no mercury, 

increased utilization would not increase 

methylmercury concentrations in their 

vicinities. Increased utilization 

generally would not cause higher peak 

concentrations of PM2.5, NOx, or ozone 

around such EGUs than is already 

occurring because peak hourly or daily 

emissions generally would not change, 

but increased utilization may make 

periods of relatively high concentrations 

more frequent. It should be noted that 

the gas-fired sources that are likely to 

become dispatched more frequently 

than at present have very low emissions 

of primary particulate matter, SO2 and 

HAP per unit of electrical output, such 

that local (or regional) air quality for 

these pollutants is likely to be affected 

very little. For natural gas-fired EGUS, 

the EPA found that regulation of HAP 

emissions ‘‘is not appropriate or 

necessary because the impacts due to 

HAP emissions from such units are 

negligible based on the results of the 

study documented in the utility 

RTC.’’ 350 In studies done by DOE/NETL 

comparing cost and performance of 

coal- and NG-fired generation, they 

assumed SO2, PM (and Hg) emissions to 

be ‘‘negligible.’’ Their studies predict 

NOx emissions from a NGCC unit to be 

approximately 10 times lower than a 

subcritical or supercritical coal-fired 

boiler. Many are also very well 

controlled for emission of NOx through 

the application of after combustion 

controls such as selective catalytic 

reduction, although not all gas-fired 

sources are so equipped. Depending on 

the specificity of the state CAA section 

111(d) plan, the state may be able to 

predict which EGUs and communities 

may be in this type of situation and to 

address any concerns about localized 

NO2 concentrations in the design of the 

CAA section 111(d) program, or 

separately from the CAA section 111(d) 

program but before its implementation. 

In any case, existing tracking systems 

will allow states and the EPA to be 

aware of the EGUs whose utilization has 

increased most significantly, and thus to 

be able to prioritize our efforts to assess 

whether air quality has changed in the 

communities in the vicinity of such 

EGUs. There are multiple mechanisms 

in the CAA to address situations in 

which air quality has degraded 

significantly. In conclusion, this 

proposed rule would result in regional 

and national pollutant reductions; 

however, there likely would also be 

some locations with more times during 

the year of relatively higher 

concentrations of pollutants with 

potential for effects on localized 

communities than would be 

experienced in the absence of the 

proposed rule. The EPA cannot exactly 

predict how emissions from specific 

EGUs would change as an outcome of 

the proposed rule due to the state-led 

implementation. Therefore, the EPA has 

concluded that it is not practicable to 

determine whether there would be 

disproportionately high and adverse 

human health or environmental effects 

on minority, low income, or indigenous 

populations from this proposed rule. 

In order to provide opportunities for 

meaningful involvement early on in the 

rule making process, the EPA has hosted 

webinars and conference calls on 

August 27, 2013, and September 9, 

2013, on the proposed rule specifically 

for environmental justice communities 

and has taken all comments and 

suggestions into consideration in the 

design of the emission guidelines. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

exposure to the pollutants addressed by 

this proposal. 

XII. Statutory Authority 

The statutory authority for this action 

is provided by sections 111, 301, 302, 

and 307(d)(1)(V) of the CAA, as 

amended (42 U.S.C. 7411, 7601, 7602, 

7607(d)(1)(V)). This action is also 

subject to section 307(d) of the CAA (42 

U.S.C. 7607(d)). 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: June 2, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60 of 

the Code of the Federal Regulations is 

proposed to be amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for Part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 2. Section 60.27 is amended by 

revising paragraph (b) to read as follows: 

§ 60.27 Actions by the Administrator. 

* * * * * 

(b) After receipt of a plan or plan 

revision, the Administrator will propose 

the plan or revision for approval or 

disapproval. The Administrator will, 

within four months after the date 

required for submission of a plan or 

plan revision, approve or disapprove 

such plan or revision or each portion 

thereof, except as provided in § 60.5715. 

* * * * * 

■ 3. Add subpart UUUU to read as 

follows: 

Subpart UUUU: Emission Guidelines 

for Greenhouse Gas Emissions and 

Compliance Times for Electric Utility 

Generating Units 

Sec. 

Introduction 

60.5700 What is the purpose of this 

subpart? 

60.5705 What pollutants are regulated by 

this subpart? 

60.5710 Am I affected by this subpart? 

60.5715 What is the review and approval 

process for my state plan? 

60.5720 What if I do not submit a plan or 

my plan is not approvable? 

60.5725 In lieu of a state plan submittal, are 

there other acceptable option(s) for a 

state to meet its section 111(d) 

obligations? 

60.5730 Is there an approval process for a 

negative declaration letter? 

60.5735 What authorities will not be 

delegated to state, local, or tribal 

agencies? 

State Plan 

60.5740 What must I include in my state 

plan? 

60.5745 Can I work with other states to 

develop a multi-state plan? 

60.5750 Can I include existing 

requirements, programs, and measures in 

my state plan? 

60.5755 What are the timing requirements 

for submitting my state plan? 

60.5760 What must I include in an initial 

submittal in lieu of a complete state 

plan? 


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60.5765 What are the state rate-based CO2

emission performance goals? 

60.5770 What is the procedure for 

converting my state rate-based CO2

emission performance goal to a massbased CO2 emissions performance goal? 

60.5775 What schedules, performance 

periods, and compliance periods must I 

include in my state plan? 

60.5780 What emission standards and 

enforcing measures must I include in my 

plan? 

60.5785 What is the procedure for revising 

my state plan? 

Applicability of State Plans to Affected EGUs 

60.5790 Does this subpart directly affect 

EGU owners and operators in my state? 

60.5795 What affected EGUs must I address 

in my state plan? 

60.5800 What affected EGUs are exempt 

from my state plan? 

60.5805 What applicable monitoring, 

recordkeeping, and reporting 

requirements do I need to include in my 

state plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.5810 What are my state recordkeeping 

requirements? 

60.5815 What are my state reporting 

requirements? 

Definitions 

60.5820 What definitions apply to this 

subpart? 

Table 1 to Subpart UUUU of Part 60—State 

Rate-based CO2 Emission Performance 

Goals (Pounds of CO2 Per Net MWh) 

Introduction 

§ 60.5700 What is the purpose of this 

subpart? 

This subpart establishes emission 

guidelines and approval criteria for state 

plans that establish emission standards 

limiting the control of greenhouse gas 

emissions from an affected steam 

generating unit, integrated gasification 

combined cycle (IGCC), or stationary 

combustion turbine. An affected steam 

generating unit, IGCC, or stationary 

combustion turbine shall, for the 

purposes of this subpart, be referred to 

as an affected EGU. These emission 

guidelines are developed in accordance 

with sections 111(d) of the Clean Air 

Act and subpart B of this part. To the 

extent any requirement of this subpart is 

inconsistent with the requirements of 

subparts A or B of this part, the 

requirements of this subpart will apply. 

§ 60.5705 What pollutants are regulated by 

this subpart? 

(a) The pollutants regulated by this 

subpart are greenhouse gases. 

(b) The greenhouse gas regulated by 

this subpart is carbon dioxide (CO2). 

§ 60.5710 Am I affected by this subpart? 

If you are the Administrator of an air 

quality program in a state with one or 

more affected EGUs that commenced 

construction on or before January 8, 

2014, you must submit a state plan to 

the U.S. Environmental Protection 

Agency (EPA) that implements the 

emission guidelines contained in this 

subpart. You must submit a negative 

declaration letter in place of the state 

plan if there are no affected EGUs for 

which construction commenced on or 

before January 8, 2014 in your state. 

§ 60.5715 What is the review and approval 

process for my state plan? 

The EPA will review your state plan 

according to § 60.27 except that under 

§ 60.27(b) the Administrator will have 

twelve months after the date required 

for submission of a plan or plan revision 

to approve or disapprove such plan or 

revision or each portion thereof. If you 

submit a request for extension under 

§ 60.5760(a) in lieu of a complete state 

plan the EPA will follow the procedure 

in § 60.5760(b). 

§ 60.5720 What if I do not submit a plan or 

my plan is not approvable? 

If you do not submit an approvable 

state plan the EPA will develop a 

Federal plan for your state according to 

§ 60.27 to implement the emission 

guidelines contained in this subpart. 

Owners and operators of affected 

entities not covered by an approved 

state plan must comply with a Federal 

plan implemented by the EPA for the 

state. The Federal plan is an interim 

action and will be automatically 

withdrawn when your state plan is 

approved. 

§ 60.5725 In lieu of a state plan submittal, 

are there other acceptable option(s) for a 

state to meet its section 111(d) obligations? 

A state may meet its CAA section 

111(d) obligations only by submitting a 

complete state plan or a negative 

declaration letter (if applicable). 

§ 60.5730 Is there an approval process for 

a negative declaration letter? 

No. The EPA has no formal review 

process for negative declaration letters. 

Once your negative declaration letter 

has been received, the EPA will place a 

copy in the public docket and publish 

a notice in the Federal Register. If, at a 

later date, an affected EGU for which 

construction commenced on or before 

January 8, 2014 is found in your state, 

a Federal plan implementing the 

emission guidelines contained in this 

subpart would automatically apply to 

that affected EGU until your state plan 

is approved. 

§ 60.5735 What authorities will not be 

delegated to state, local, or tribal agencies? 

The authorities that will not be 

delegated to State, local, or tribal 

agencies are specified in paragraph (a) 

of this section. 

(a) Approval of alternatives, not 

already approved by this subpart, to the 

emissions performance goals in Table 1 

to this subpart established under 

§ 60.5755. 

(b) [Reserved] 

State Plan 

§ 60.5740 What must I include in my state 

plan? 

(a) You must include the elements 

described in paragraphs (a)(1) through 

(11) of this section in your state plan. 

(1) Identification of affected entities, 

including an inventory of CO2 emissions 

from affected EGUs during the most 

recent calendar year prior to the 

submission of the plan for which data 

is available. 

(2) A description of plan approach 

and the geographic scope of a plan (state 

or multi-state), including, if relevant, 

identification of multi-state plan 

participants and geographic boundaries 

related to plan elements. 

(3) Identification of the state emission 

performance level for affected entities 

that will be achieved through 

implementation of the plan. 

(i) The plan must specify the average 

emissions performance that the plan 

will achieve for the following periods: 

(A) The 10 year interim plan 

performance period of 2020 through 

2029. 

(B) The single projection year of 2030. 

(ii) The identified emission 

performance level for each plan 

performance period in paragraph 

(a)(3)(i) of this section must be 

equivalent to or better than the levels of 

the rate-based CO2 emission 

performance goals in Table 1 of this 

Subpart for affected entities in your 

state. The emission performance levels 

may be in either a rate-based form or a 

mass based form which is calculated 

according to § 60.5770. The CO2

emission performance level specified 

must include either of the following as 

applicable: 

(A) For a rate-based CO2 emission 

performance level, the identified level 

must represent the CO2 emissions rate, 

in pounds of CO2 per MWh of net 

energy output that will be achieved by 

affected entities. 

(B) For a mass-based CO2 emission 

performance level, the identified level 

of performance must represent the total 

tons of CO2 that will be emitted by 

affected entities during each plan 

performance period. 


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(iii) For the interim plan performance 

period you must identify the emission 

performance levels anticipated under 

the plan during each year 2020 through 

2029. 

(4) A demonstration that the plan is 

projected to achieve each of the state’s 

emission performance levels for affected 

entities according to paragraph (a)(3) of 

this section. 

(5) Identification of emission 

standards for each affected entity, 

compliance periods for each emission 

standard, and demonstration that the 

emission standards are, when taken 

together, sufficiently protective to meet 

the state emissions performance level. 

(6) A demonstration that each 

emission standard is quantifiable, nonduplicative, permanent, verifiable, and 

enforceable with respect to an affected 

entity. 

(7) If your state plan does not require 

achievement of the full level of required 

emission performance, and the 

identified interim increments of 

performance in paragraph (a)(3)(iii) of 

this section, through emission limits on 

EGUs, the plan must specify the 

following: 

(i) Program implementation 

milestones (e.g., start of an end-use 

energy efficiency program, retirement of 

an affected EGU, or increase in portfolio 

requirements under a renewable 

portfolio standard) and milestone dates 

that are appropriate to the requirements, 

programs, and measures included in the 

plan. 

(ii) Corrective measures that will be 

implemented in the event that the 

comparison required by § 60.5815(b) of 

projected versus actual emissions 

performance of affected entities shows 

that actual emissions performance is 

greater than 10 percent in excess to 

projected plan performance for the 

period described in § 60.5775(c)(1), and 

a process and schedule for 

implementing such corrective measures. 

(8) Identification of applicable 

monitoring, reporting, and 

recordkeeping requirements for each 

affected entity. If applicable, these 

requirements must be consistent with 

the requirements specified in § 60.5810. 

(9) Description of the process, 

contents, and schedule for annual state 

reporting to the EPA about plan 

implementation and progress including 

information required under § 60.5815. 

(10) Certification that the hearing on 

the state plan was held, a list of 

witnesses and their organizational 

affiliations, if any, appearing at the 

hearing, and a brief written summary of 

each presentation or written 

submission. 

(11) Supporting material including: 

(i) Materials demonstrating the state’s 

legal authority to carry out each 

component of its plan, including 

emissions standards; 

(ii) Materials supporting the projected 

emissions performance level that will be 

achieved by affected entities under the 

plan, according to paragraph (a)(4) of 

this section; 

(iii) Materials supporting the 

projected mass-based emission 

performance goal, calculated pursuant 

to § 60.5770, if applicable; and 

(iv) Materials necessary to support 

evaluation of the plan by the EPA. 

(b) You must follow the requirements 

of subpart B of this part (Adoption and 

Submittal of state plans for Designated 

Facilities) and demonstrate that they 

were met in your state plan. 

§ 60.5745 Can I work with other states to 

develop a multi-state plan? 

A multi-state plan may be submitted, 

provided it is signed by authorized 

officials for each of the states 

participating in the multi-state plan. In 

this instance, the joint submittal will 

have the same legal effect as an 

individual submittal for each 

participating state. A multi-state plan 

will include all the required elements 

for a single-state plan specified in 

§ 60.5740(a). A multi-state plan, if 

submitted by a state, must: 

(a) Demonstrate CO2 emission 

performance jointly for all affected 

entities in all states participating in the 

multi-state plan, as follows: 

(1) For states demonstrating 

performance based on the CO2 emission 

rate, the level of performance identified 

in the multi-state plan pursuant to 

§ 60.5740(a)(3) will be a weighted (by 

net energy output) average lb CO2/MWh 

emission rate to be achieved by all 

affected EGUs in the multi-state area 

during the plan performance period; or 

(2) For states demonstrating 

performance based on mass CO2

emissions, the level of performance 

identified in the multi-state plan 

pursuant to 60.5740(a)(3) will be total 

CO2 emissions by all affected EGUs in 

the multi-state area during the plan 

performance period. 

(b) Assign among states, according to 

a formula in the multi-state plan, 

avoided CO2 emissions resulting from 

emission standards contained in the 

plan, from affected entities in states 

participating in the multi-state plan. 

§ 60.5750 Can I include existing 

requirements, programs, and measures in 

my state plan? 

(a) Yes, you may include existing 

requirements, programs and measures in 

your plan according to paragraphs (b) 

through (d) of this section. 

(b) Existing state programs, 

requirements, and measures, may 

qualify for use in demonstrating that a 

state plan achieves the required level of 

emission performance specified in a 

plan, according to § 60.5740(a)(3). 

(c) Existing state programs, 

requirements, and measures, may 

qualify for use in projecting that a state 

plan will achieve the required level of 

emission performance specified in a 

plan, according to § 60.5740(a)(4). 

(d) Emission impacts of existing 

programs, requirements, and measures 

that occur during a plan performance 

period may be recognized in meeting or 

projecting CO2 emission performance by 

affected EGUs according to 

§ 60.5740(a)(3) and (4), as long as they 

meet the following requirements: 

(1) Actions taken pursuant to an 

existing state program, requirement, or 

measure, such as compliance with a 

regulatory obligation or initiation of an 

action related to a program or measure, 

must occur after June 18, 2014; and 

(2) The existing state program, 

requirement, or measure, and any 

related actions taken pursuant to such 

program, requirement, or measure, meet 

the applicable requirements pursuant to 

§ 60.5740(a) and § 60.5780. 

§ 60.5755 What are the timing 

requirements for submitting my state plan? 

(a) You must submit your state plan 

with the information in § 60.5740 by 

June 30, 2016 unless you are submitting 

a request for extension according to 

paragraphs (b) or (c) of this section. 

(b) For a state seeking a one year 

extension for a complete plan submittal 

you must include the information in 

§ 60.5760(a) in a submittal by June 30, 

2016 to receive an extension to submit 

your complete state plan by June 30, 

2017. 

(c) For states in a multi-state plan 

seeking a two year extension for a 

complete plan submittal you must 

include the information in § 60.5760(a) 

in a submittal by June 30, 2016 to 

receive an extension to submit your 

complete multi-state plan by June 30, 

2018. 

§ 60.5760 What must I include in an initial 

submittal in lieu of a complete state plan? 

(a) You must include the following 

required elements in an initial submittal 

in lieu of a complete state plan: 

(1) A description of the plan approach 

and progress made to date in developing 

each of the plan elements in § 60.5740; 

(2) An initial projection of the level of 

emission performance that will be 

achieved under the complete plan; 

(3) A commitment by the state to 

maintain existing state programs and 


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measures that limit or avoid CO2

emissions from affected entities (e.g., 

renewable energy standards, unitspecific limits on operation or fuel 

utilization), which must at a minimum 

apply during the interim period prior to 

state submission and EPA approval of a 

complete plan, and must continue to 

apply in lieu of a complete plan if one 

is ultimately not submitted and 

approved; 

(4) Justification of why additional 

time is needed to submit a complete 

plan; 

(5) A comprehensive roadmap for 

completing the plan, including process, 

analytical methods and schedule 

(including milestones) specifying when 

all necessary plan components will be 

complete (e.g., projection of emission 

performance; implementing legislation, 

regulations and agreements; necessary 

approvals); 

(6) Identification of existing and 

future programs, requirements, and 

measures the state intends to include in 

the plan; 

(7) If a multi-state plan is being 

developed, an executed agreement(s) 

with other states (e.g., MOU) 

participating in the development of the 

multistate plan; and 

(8) A commitment to submit a 

complete plan by June 30, 2017, for a 

single-state plan, or June 30, 2018, for a 

multi-state plan, and actions the state 

will take to show progress in addressing 

incomplete plan components prior to 

submittal of the complete plan. 

(9) A description of all steps the state 

has already taken in furtherance of 

actions needed to finalize a complete 

plan. 

(10) Evidence of an opportunity for 

public comment and a response to any 

significant comments received on issues 

relating to the approvability of the 

initial plan. 

(b) You must submit either a complete 

state plan or an initial submittal by June 

30, 2016. Where an initial submittal is 

submitted in lieu of a complete state 

plan the due date of a complete state 

plan will be June 30, 2017, for a singlestate plan, or June 30, 2018, for a multistate plan unless a state is notified 

within 60 days of the EPA receiving the 

initial submittal in paragraph (a) of this 

section that the EPA finds the initial 

submittal does not meet the 

requirements listed in paragraph (a) of 

this section. 

§ 60.5765 What are the state rate-based 

CO2 emissions performance goals? 

(a) The annual average state ratebased CO2 emission performance goals 

for the interim performance periods of 

2020 through 2029, and the final 2030 

and thereafter period are respectively 

listed in Table 1 of this Subpart. The 

state rate-based CO2 emission 

performance goal may be converted to a 

mass-based emission performance goal 

according to § 60.5770. 

(b)[Reserved] 

§ 60.5770 What is the procedure for 

converting my state rate-based CO2

emission performance goal to a massbased CO2 emissions performance goal? 

(a) If the plan adopts a mass-based 

goal according to § 60.5740(a)(3), the 

plan must identify the mass-based goal, 

in tons of CO2 emitted by affected EGUs 

over the plan performance period, and 

include a description of the analytic 

process, tools, methods, and 

assumptions used to convert from the 

rate-based goal for the state identified in 

Table 1 of this Subpart to an equivalent 

mass-based goal. The conversion 

process must include following 

requirements: 

(1) The process, tools, methods, and 

assumptions used in the conversion of 

the rate-based goal must be included in 

your state plan according to 

§ 60.5740(a)(11). 

(2) The material supporting the 

conversion of the rate-based goal, 

including results, data, and 

descriptions, must be include in a state 

plan according to § 60.5740(a)(11). 

(3) The conversion must represent the 

tons of CO2 emissions that are projected 

to be emitted by affected EGUs, in the 

absence of emission standards 

contained in the plan, if the affected 

EGUs were to perform at an average lb 

CO2/MWh rate equal to the rate-based 

goal for the state identified in Table 1 

of this Subpart. 

(b) [Reserved] 

§ 60.5775 What schedules, performance 

periods, and compliance periods must I 

include in my state plan? 

(a) Your state plan must include a 

schedule of compliance for each 

affected entity regulated under the plan. 

(b) Your state plan must include 

compliance periods, as defined in 

section § 60.5820, for each affected 

entity regulated under the plan. 

(c) For the interim performance 

period of 2020–2029 your state must 

meet the requirements in paragraphs 

(c)(1) and (2) of this section. 

(1) Your state plan must include 

increments of emissions performance 

(either rate based or mass based with 

respect to the interim level of 

performance set in the state plan) within 

the interim performance period for 

every 2-rolling calendar years starting 

January 1, 2020 and ending in 2028 (i.e. 

2020–2021, 2021–2022, 2022–2023, 

etc.), unless other periods that ensure 

regular progress in the interim period 

are approved by the Administrator. 

(2) At the end of 2029 your state must 

meet the interim emissions performance 

level specified in § 60.5740(a)(3) as 

averaged over the plan performance 

period 2020–2029. 

(d) During the final performance 

period, 2030 and thereafter, your state 

must meet the final emission 

performance level specified in 

§ 60.5740(a)(3) on a 3-calendar year 

rolling average starting January 1, 2030 

(i.e., 2030–2032, 2031–2033, 2032–2034, 

etc.). 

(e) You must include the provisions of 

your state plan which demonstrate 

progress and compliance with the 

requirements in this § 60.5775 and 

§ 60.5740 in your state’s annual report 

required in § 60.5815. 

§ 60.5780 What emission standards and 

enforcing measures must I include in my 

plan? 

(a) Your state plan shall include 

emission standard(s) that are 

quantifiable, verifiable, non-duplicative, 

permanent, and enforceable with 

respect to each affected entity. The plan 

shall include the methods by which 

each emission standard meets each of 

the following requirements in 

paragraphs (b) through (f) of this 

section. 

(b) An emission standard is 

quantifiable with respect to an affected 

entity if it can be reliably measured, in 

a manner that can be replicated. 

(c) An emission standard is verifiable 

with respect to an affected entity if 

adequate monitoring, recordkeeping and 

reporting requirements are in place to 

enable the state and the Administrator 

to independently evaluate, measure, and 

verify compliance with the emission 

standard. 

(d) An emission standard is nonduplicative with respect to an affected 

entity if it is not already incorporated as 

an emission standard in another state 

plan unless incorporated in multi-state 

plan. 

(e) An emission standard is 

permanent with respect to an affected 

entity if the emission standard must be 

met for each compliance period, or 

unless it is replaced by another 

emission standard in an approved plan 

revision, or the state demonstrates in an 

approved plan revision that the 

emission reductions from the emission 

standard are no longer necessary for the 

state to meet its state level of 

performance. 

(f) An emission standard is 

enforceable against an affected entity if: 

(1) A technically accurate limitation 

or requirement and the time period for 


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the limitation or requirement is 

specified; 

(2) Compliance requirements are 

clearly defined; 

(3) The affected entities responsible 

for compliance and liable for violations 

can be identified; 

(4) Each compliance activity or 

measure is enforceable as a practical 

matter; and 

(5) The Administrator and the state 

maintain the ability to enforce 

violations and secure appropriate 

corrective actions pursuant to sections 

113(a) through (h) of the Act. 

§ 60.5785 What is the procedure for 

revising my state plan? 

State plans can only be revised with 

approval by the Administrator. If one (or 

more) of the elements of the state plan 

set in § 60.5740 require revision with 

respect to reaching the emission 

performance goal set in § 60.5765 a 

request may be submitted to the 

Administrator indicating the proposed 

corrections to the state plan to ensure 

the emission performance goal is met. 

Applicability of State Plans to Affected 

EGUs 

§ 60.5790 Does this subpart directly affect 

EGU owners and operators in my state? 

(a) This subpart does not directly 

affect EGU owners and operators in your 

state. However, EGU owners and 

operators must comply with the state 

plan that a state develops to implement 

the emission guidelines contained in 

this subpart. 

(b) If a state does not submit an 

approvable plan or initial submittal to 

implement and enforce the emission 

guidelines contained in this subpart by 

June 30, 2016, the EPA will implement 

and enforce a Federal plan, as provided 

in § 60.5740, to ensure that each affected 

EGU within the state that commenced 

construction on or before January 8, 

2014 reaches compliance with all the 

provisions of this subpart. 

§ 60.5795 What affected EGUs must I 

address in my state plan? 

(a) The EGUs that must be addressed 

by your state plan are any affected steam 

generating unit, IGCC, or stationary 

combustion turbine that commences 

construction on or before January 8, 

2014. 

(b) An affected EGU is a steam 

generating unit, integrated gasification 

combined cycle (IGCC), or stationary 

combustion turbine that meets the 

relevant applicability conditions 

specified in paragraph (b)(1) or (2) of 

this section. 

(1) A steam generating unit or IGCC 

that has a base load rating greater than 

73 MW (250 MMBtu/h) heat input of 

fossil fuel (either alone or in 

combination with any other fuel) and 

was constructed for the purpose of 

supplying one-third or more of its 

potential electric output and more than 

219,000 MWh net-electric output to a 

utility distribution system on an annual 

basis. 

(2) A stationary combustion turbine 

that has a base load rating greater than 

73 MW (250 MMBtu/h), was 

constructed for the purpose of 

supplying, and supplies, one-third or 

more of its potential electric output and 

more than 219,000 MWh net-electrical 

output to a utility distribution system 

on a 3-year rolling average basis, 

combusts fossil fuel for more than 10.0 

percent of the heat input during a 3-year 

rolling average basis and combusts over 

90% natural gas on a heat input basis on 

a 3-year rolling average basis. 

§ 60.5800 What affected EGUs are exempt 

from my state plan? 

Affected EGUs that are exempt from 

your state plan include: those that are 

subject to subpart TTTT as a result of 

commencing construction or 

reconstruction after the subpart TTTT 

applicability date; and those subject to 

subpart TTTT as a result of commencing 

modification or reconstruction prior 

becoming subject to an applicable state 

plan. 

§ 60.5805 What applicable monitoring, 

recordkeeping, and reporting requirements 

do I need to include in my state plan for 

affected EGUs? 

(a) A state plan must include 

monitoring that is no less stringent that 

what is described in (a)(1) through (6) of 

this section. 

(1) If an affected EGU is required to 

meet a rate based emission standard 

they must prepare a monitoring plan in 

accordance with the applicable 

provisions in § 75.53(g) and (h) of this 

chapter. 

(2) An affected EGU must measure the 

hourly CO2 mass emissions from each 

affected unit using the procedures in 

paragraphs (a)(2)(i) through (v) of this 

section, except as provided in paragraph 

(a)(3) of this section. 

(i) An affected EGU must install, 

certify, operate, maintain, and calibrate 

a CO2 continuous emissions monitoring 

system (CEMS) to directly measure and 

record CO2 concentrations in the 

affected EGU exhaust gases emitted to 

the atmosphere and an exhaust gas flow 

rate monitoring system according to 

§ 75.10(a)(3)(i) of this chapter. If an 

affected EGU measures CO2

concentration on a dry basis, they must 

also install, certify, operate, maintain, 

and calibrate a continuous moisture 

monitoring system, according to 

§ 75.11(b) of this chapter. 

(ii) For each monitoring system an 

affected EGU uses to determine the CO2

mass emissions, they must meet the 

applicable certification and quality 

assurance procedures in § 75.20 of this 

chapter and Appendices B and D to part 

75 of this chapter. 

(iii) An affected EGU must use a laser 

device to measure the dimensions of 

each exhaust gas stack or duct at the 

flow monitor and the reference method 

sampling locations prior to the initial 

setup (characterization) of the flow 

monitor. For circular stacks, an affected 

EGU must measure the diameter at three 

or more distinct locations and average 

the results. For rectangular stacks or 

ducts, an affected EGU must measure 

each dimension (i.e., depth and width) 

at three or more distinct locations and 

average the results. If the flow rate 

monitor or reference method sampling 

site is relocated, an affected EGU must 

repeat these measurements at the new 

location. 

(iv) An affected EGU must use only 

unadjusted exhaust gas volumetric flow 

rates to determine the hourly CO2 mass 

emissions from the affected facility; an 

affected EGU must not apply the bias 

adjustment factors described in section 

7.6.5 of Appendix A to part 75 of this 

chapter to the exhaust gas flow rate 

data. 

(v) If an affected EGU chooses to use 

Method 2 in Appendix A–1 to this part 

to perform the required relative 

accuracy test audits (RATAs) of the part 

75 flow rate monitoring system, they 

must use a calibrated Type-S pitot tube 

or pitot tube assembly. An affected EGU 

must not use the default Type-S pitot 

tube coefficient. 

(3) If an affected EGU exclusively 

combusts liquid fuel and/or gaseous fuel 

as an alternative to complying with 

paragraph (b) of this section, they may 

determine the hourly CO2 mass 

emissions by using Equation G–4 in 

Appendix G to part 75 of this chapter 

according to the requirements in 

paragraphs (a)(3)(i) and (ii) of this 

section. 

(i) An affected EGU must implement 

the applicable procedures in appendix 

D to part 75 of this chapter to determine 

hourly unit heat input rates (MMBtu/h), 

based on hourly measurements of fuel 

flow rate and periodic determinations of 

the gross calorific value (GCV) of each 

fuel combusted. 

(ii) An affected EGU may determine 

site-specific carbon-based F-factors (Fc) 

using Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and may use these Fc values in the 


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emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(4) An affected EGU must install, 

calibrate, maintain, and operate a 

sufficient number of watt meters to 

continuously measure and record on an 

hourly basis net electric output. 

Measurements must be performed using 

0.2 accuracy class electricity metering 

instrumentation and calibration 

procedures as specified under ANSI 

Standards No. C12.20. Further, an 

affected EGU that is a combined heat 

and power facility must install, 

calibrate, maintain and operate 

equipment to continuously measure and 

record on an hourly basis useful thermal 

output and, if applicable, mechanical 

output, which are used with net electric 

output to determine net energy output. 

(5) In accordance with § 60.13(g), if 

two or more affected EGUs that 

implement the continuous emissions 

monitoring provisions in paragraph 

(a)(2) of this section share a common 

exhaust gas stack and are subject to the 

same emissions standard, they may 

monitor the hourly CO2 mass emissions 

at the common stack in lieu of 

monitoring each EGU separately. If an 

affected EGU chooses this option, the 

hourly net electric output for the 

common stack must be the sum of the 

hourly net electric output of the 

individual affected facility and you 

must express the operating time as 

‘‘stack operating hours’’ (as defined in 

§ 72.2 of this chapter). 

(6) In accordance with § 60.13(g), if 

the exhaust gases from an affected EGU 

that implements the continuous 

emissions monitoring provisions in 

paragraph (a)(2) of this section are 

emitted to the atmosphere through 

multiple stacks (or if the exhaust gases 

are routed to a common stack through 

multiple ducts and you elect to monitor 

in the ducts), they must monitor the 

hourly CO2 mass emissions and the 

‘‘stack operating time’’ (as defined in 

§ 72.2 of this chapter) at each stack or 

duct separately. In this case, an affected 

EGU must determine compliance with 

an applicable emissions standard by 

summing the CO2 mass emissions 

measured at the individual stacks or 

ducts and dividing by the net energy 

output for the affected EGU. 

(b) An affected EGU must maintain 

records for at least 10 years following 

the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(1) An affected EGU must maintain 

each record on site for at least 2 years 

after the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record, according to 

§ 60.7. An affected EGU may maintain 

the records off site and electronically for 

the remaining year(s). 

(c) An affected EGU must include in 

a report required by the state plan 

covering each compliance period all 

hourly CO2 emissions and all hourly net 

electric output and all hourly net energy 

output measurements for a CHP facility 

calculated from data monitored 

according to paragraph (a) of this 

section. 

Recordkeeping and Reporting 

Requirements 

§ 60.5810 What are my state 

recordkeeping requirements? 

(a) States must keep records of all 

plan components, plan requirements, 

supporting documentation, and the 

status of meeting the plan requirements 

defined in the state plan on an annual 

basis during the interim plan 

performance period from 2020–2029. 

After 2029 states must keep records of 

all information that is used to support 

any continued effort to meet the final 

emissions performance goal. 

(b) States must keep records of all 

data submitted by each affected entity 

that is used to determine compliance 

with each affected entity’s emissions 

standard. 

(c) If a state has a requirement for 

hourly CO2 emissions and net 

generation information to be used to 

calculate compliance with an annual 

emissions standard for affected EGUs, 

any information that is submitted to the 

EPA electronically pursuant to 

requirements in Part 75 would meet the 

recordkeeping requirement of this 

section and a state would not need to 

keep records of information that would 

be in duplicate of paragraph (b) of this 

section. 

(d) A state must keep records at 

minimum for 20 years. 

§ 60.5815 What are my state reporting 

requirements? 

(a) You must submit an annual report 

covering each calendar year no later 

than July 1 of the following year, 

starting July 1 2021. The annual report 

must include the following: 

(1) The level of emissions 

performance achieved by all affected 

entities and identification of whether 

affected entities are on schedule to meet 

the applicable level of emissions 

performance for affected entities during 

the plan performance period and 

compliance periods, as specified in the 

plan. 

(2) The level of emissions 

performance achieved by all affected 

EGUs during the reporting period, and 

prior reporting periods, expressed as 

average CO2 emissions rate or total mass 

CO2 emissions, consistent with the plan 

approach, and identification of whether 

affected EGUs are on schedule to meet 

the applicable level of emissions 

performance for affected EGUs during 

the plan performance period, as 

specified in the plan. 

(3) A list of affected entities and their 

compliance status with the applicable 

emissions standards specified in the 

state plan. 

(4) A list of all affected EGUs and 

their reported CO2 emissions 

performance for each compliance period 

during the reporting period, and prior 

reporting periods. 

(5) All other required information, as 

specified in your state plan according to 

§ 60.5740(a)(9). 

(6) All information required by 

§ 60.5775(e). 

(b) For each two-year period in 

§ 60.5775(c)(1), you must compare the 

average CO2 emission performance 

achieved by affected entities in the state 

versus the CO2 emission performance 

projected in the state plan. If actual 

emission performance is greater than 10 

percent in excess to projected plan 

performance for a two-year comparison 

period, you must explain the reasons for 

the deviation and specify the corrective 

actions that will be taken to ensure that 

the required interim and final levels of 

emission performance in the plan will 

be met. The information required in this 

paragraph must be included in the 

annual report required by paragraph (a) 

of this section. 

(c) You must include in your 2029 

annual report (which is subsequently 

due by July 1, 2030) the calculation of 

average emissions over the 2020–2029 

interim performance period used to 

determine compliance with your 

interim emission performance level. The 

calculated value must be in units 

consistent with your interim emission 

performance level. 

(d) You must include in each report, 

starting with the 2032 annual report 

(which is subsequently due by July 1, 

2033), a 3-calendar year rolling average 

used to determine compliance with the 

final emission performance level. The 

calculated value must be in units 

consistent with your final emission 

performance level. 

Definitions 

§ 60.5820 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subparts A (General Provisions) and B of 

this part. 


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Affected electric generating unit or 

Affected EGU means a steam generating 

unit, an IGCC facility, or a stationary 

combustion turbine that meets the 

applicability conditions in section 

§ 60.5795. 

Affected Entity shall mean any of the 

following: An affected EGU, or another 

entity with obligations under this 

subpart for the purpose of meeting the 

emissions performance goal 

requirements in these emission 

guidelines. 

Base load rating means the maximum 

amount of heat input (fuel) that a steam 

generating unit can combust on a steady 

state basis, as determined by the 

physical design and characteristics of 

the steam generating unit at ISO 

conditions. For a stationary combustion 

turbine, base load rating means 100 

percent of the design heat input 

capacity of the simple cycle portion of 

the stationary combustion turbine at ISO 

conditions (heat input from duct 

burners is not included). 

CO2 emissions performance goal 

means the rate-based CO2 emissions 

performance goal specified for a state in 

Table 1 of this subpart, or a translated 

mass-based form of that goal. 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17), 

coal refuse, and petroleum coke. 

Synthetic fuels derived from coal for the 

purpose of creating useful heat, 

including but not limited to solventrefined coal, gasified coal (not meeting 

the definition of natural gas), coal-oil 

mixtures, and coal-water mixtures are 

included in this definition for the 

purposes of this subpart. 

Combined cycle facility means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit to generate 

additional electricity. 

Combined heat and power facility or 

CHP facility, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that that use a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal output from the same primary 

energy source. 

Compliance period means the period 

of time, set forth by a state in its state 

plan, during which each affected entity 

must demonstrate compliance with an 

applicable emissions standard, and shall 

be no greater than a three year period for 

a mass-based plan, and shall be no 

greater than a one year period for a ratebased plan. 

Emission performance level in a state 

plan means the level of emissions 

performance for affected entities 

specified in a state plan, according to 

§ 60.5740. 

Emission standard means in addition 

to the definition in § 60.21, any 

requirement applicable to any affected 

entity other than an affected source that 

has the effect of reducing utilization of 

one or more affected sources, thereby 

avoiding emissions from such sources, 

including, for example, renewable 

energy and demand-side energy 

efficiency measures requirements. 

Excess emissions means a specified 

averaging period over which the CO2

emissions rate is higher than an 

applicable emissions standard or an 

averaging period during which an 

affected EGU is not in compliance with 

any other emission limitation specified 

in an emission standard. 

Existing state program, requirement, 

or measure means, in the context of a 

state plan, a regulation, requirement, 

program, or measure administered by a 

state, utility, or other entity that is 

currently established. This may include 

a regulation or other legal requirement 

that includes past, current, and future 

obligations, or current programs and 

measures that are in place and are 

anticipated to be continued or expanded 

in the future, in accordance with 

established plans. An existing state 

program, requirement, or measure may 

have past, current, and future impacts 

on EGU CO2 emissions. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Gaseous fuel means any fuel that is 

present as a gas at ISO conditions and 

includes, but is not limited to, natural 

gas, refinery fuel gas, process gas, cokeoven gas, synthetic gas, and gasified 

coal. 

Heat recovery steam generating unit 

(HRSG) means a unit in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Integrated gasification combined 

cycle facility or IGCC facility means a 

combined cycle facility that is designed 

to burn fuels containing 50 percent (by 

heat input) or more solid-derived fuel 

not meeting the definition of natural gas 

plus any integrated equipment that 

provides electricity or useful thermal 

output to either the affected facility or 

auxiliary equipment. The Administrator 

may waive the 50 percent solid-derived 

fuel requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the unit during operation. 

ISO conditions means 288 Kelvin (15° 

C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Liquid fuel means any fuel that is 

present as a liquid at ISO conditions 

and includes, but is not limited to, 

distillate oil and residual oil. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected facility, generate 

electricity and/or thermal output, or to 

enhance the performance of the affected 

facility. Mechanical energy measured in 

horsepower hour should be converted 

into MWh by multiplying it by 745.7 

then dividing by 1,000,000. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: Landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

Net-electric output means the amount 

of gross generation the generator(s) 

produce (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)), as measured at the 

generator terminals, less the electricity 

used to operate the plant (i.e., auxiliary 

loads); such uses include fuel handling 

equipment, pumps, fans, pollution 

control equipment, other electricity 

needs, and transformer losses as 

measured at the transmission side of the 

step up transformer (e.g., the point of 

sale). 

Net energy output means: 

(1) The net electric or mechanical 

output from the affected facility, plus 75 

percent of the useful thermal output 

measured relative to SATP conditions 

that is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the unit 

(e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power 

facilities where at least 20.0 percent of 


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the total gross energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total gross energy 

output consists of useful thermal output 

on a rolling 3 year basis, the net electric 

or mechanical output from the affected 

facility divided by 0.95, plus 75 percent 

of the useful thermal output measured 

relative to SATP conditions that is not 

used to generate additional electric or 

mechanical output or to enhance the 

performance of the unit (e.g., steam 

delivered to an industrial process for a 

heating application). 

Petroleum means crude oil or a fuel 

derived from crude oil, including, but 

not limited to, distillate and residual oil. 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

Standard ambient temperature and 

pressure (SATP) conditions means 

298.15 Kelvin (25° C, 77 °F)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) 

pressure. The enthalpy of water at SATP 

conditions is 50 Btu/lb. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, 

control systems (except emissions 

control equipment), heat recovery 

system, fuel compressor, heater, and/or 

pump, post-combustion emissions 

control technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self-propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly it is considered a 

steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Useful thermal output means the 

thermal energy made available for use in 

any industrial or commercial process, or 

used in any heating or cooling 

application, i.e., total thermal energy 

made available for processes and 

applications other than electric 

generation, mechanical output at the 

affected facility, or to directly enhance 

the performance of the affected facility 

(e.g., economizer output is not useful 

thermal output, but thermal energy used 

to reduce fuel moisture is considered 

useful thermal output). Useful thermal 

output for affected facilities with no 

condensate return (or other thermal 

energy input to the affected facility) or 

where measuring the energy in the 

condensate (or other thermal energy 

input to the affected facility) would not 

meaningfully impact the emission rate 

calculation is measured against the 

energy in the thermal output at SATP 

conditions. Affected facilities with 

meaningful energy in the condensate 

return (or other thermal energy input to 

the affected facility) must measure the 

energy in the condensate and subtract 

that energy relative to SATP conditions 

from the measured thermal output. 

TABLE 1 TO SUBPART UUUU OF PART 60—STATE RATE-BASED CO2 EMISSION PERFORMANCE GOALS

[Pounds of CO2 per net MWh] 

State Interim goal Final goal 

Alabama ........................................................................................................................................................... 1,147 1,059 

Alaska .............................................................................................................................................................. 1,097 1,003 

Arizona ............................................................................................................................................................. 735 702 

Arkansas .......................................................................................................................................................... 968 910 

California .......................................................................................................................................................... 556 537 

Colorado .......................................................................................................................................................... 1,159 1,108 

Connecticut ...................................................................................................................................................... 597 540 

Delaware .......................................................................................................................................................... 913 841 

Florida .............................................................................................................................................................. 794 740 

Georgia ............................................................................................................................................................ 891 834 

Hawaii .............................................................................................................................................................. 1,378 1,306 

Idaho ................................................................................................................................................................ 244 228 

Illinois ............................................................................................................................................................... 1,366 1,271 

Indiana ............................................................................................................................................................. 1,607 1,531 

Iowa ................................................................................................................................................................. 1,341 1,301 

Kansas ............................................................................................................................................................. 1,578 1,499 

Kentucky .......................................................................................................................................................... 1,844 1,763 

Louisiana .......................................................................................................................................................... 948 883 

Maine ............................................................................................................................................................... 393 378 

Maryland .......................................................................................................................................................... 1,347 1,187 

Massachusetts ................................................................................................................................................. 655 576 

Michigan ........................................................................................................................................................... 1,227 1,161 

Minnesota ........................................................................................................................................................ 911 873 

Mississippi ........................................................................................................................................................ 732 692 

Missouri ............................................................................................................................................................ 1,621 1,544 

Montana ........................................................................................................................................................... 1,882 1,771 

Nebraska .......................................................................................................................................................... 1,596 1,479 

Nevada ............................................................................................................................................................. 697 647 

New Hampshire ............................................................................................................................................... 546 486 

New Jersey ...................................................................................................................................................... 647 531 

New Mexico ..................................................................................................................................................... 1,107 1,048 

New York ......................................................................................................................................................... 635 549 

North Carolina .................................................................................................................................................. 1,077 992 

North Dakota .................................................................................................................................................... 1,817 1,783 


sroberts on DSK5SPTVN1PROD with PROPOSALS
34958 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

TABLE 1 TO SUBPART UUUU OF PART 60—STATE RATE-BASED CO2 EMISSION PERFORMANCE GOALS—Continued 

[Pounds of CO2 per net MWh] 

State Interim goal Final goal 

Ohio ................................................................................................................................................................. 1,452 1,338 

Oklahoma ......................................................................................................................................................... 931 895 

Oregon ............................................................................................................................................................. 407 372 

Pennsylvania .................................................................................................................................................... 1,179 1,052 

Rhode Island .................................................................................................................................................... 822 782 

South Carolina ................................................................................................................................................. 840 772 

South Dakota ................................................................................................................................................... 800 741 

Tennessee ....................................................................................................................................................... 1,254 1,163 

Texas ............................................................................................................................................................... 853 791 

Utah ................................................................................................................................................................. 1,378 1,322 

Virginia ............................................................................................................................................................. 884 810 

Washington ...................................................................................................................................................... 264 215 

West Virginia .................................................................................................................................................... 1,748 1,620 

Wisconsin ......................................................................................................................................................... 1,281 1,203 

Wyoming .......................................................................................................................................................... 1,808 1,714 

[FR Doc. 2014–13726 Filed 6–17–14; 8:45 am] 

BILLING CODE 6560–50–P 


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