From: Culligan, Kevin [mailto:Culligan.Kevin@epa.gov] 

Sent: Friday, May 30, 2014 10:13 PM 

To: Higgins, Cortney 

Cc: Wayland, Robertj; Adams, Darryl; Curry, Bridgid 

Subject: FW: Final version of EGU GHG EG proposal 

<< EO12866_EGU GHG Existing Source 2060-AR33 Proposal_20140530.docx >> 
***E.O. 12866 Review – Revised Version – Do Not Cite, Quote or Release During 

Review*** 

6560-50 

EO12866_EGU GHG Existing Source 2060-AR33 Proposal_20140530 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[EPA-HQ-OAR-2013-0602; FRL-xxxx-xx]

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 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 fuelfired power plants in the United States.

DATES: Comments on the proposed rule. Comments must be received 

on or before [INSERT THE DATE 120 DAYS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE]. 

Comments on the information collection request. Under the 
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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 

[INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF THIS 

PROPOSED RULE], a comment to the OMB is best assured of having 

its full effect if the OMB receives it by [INSERT THE DATE 30 

DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER OF 

THIS PROPOSED RULE]. 

Public Hearing. Four public hearings will be convened. Two 

public hearings will be held on July 29, 2014, one 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 in Denver, Colorado, at EPA’s 

Region 8 Building, 1595 Wynkoop Street, Denver, Colorado 80202. 

The other two public hearings will be held on July 31, 2014, one 

in Washington, DC, at the William Jefferson Clinton East 

Building, Room 1152, 1201 Constitution Avenue, NW, Washington, 

DC 20004, and one in Pittsburgh, Pennsylvania at the William S. 

Moorhead Federal Building, Room 1310, 1000 Liberty Avenue 

Pittsburgh, Pennsylvania 15222. The public hearings in 

Pittsburgh, Pennsylvania, Washington, DC, and Atlanta, Georgia, 

will convene at 9:00 a.m. and end at 8:00 p.m. (Eastern Standard 

Time). The public hearing in Denver, Colorado, will convene at 
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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. 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 
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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/carbon-pollution-standards/. 

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-
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HQ-OAR-2013-0602 in the subject line of the message. 

Facsimile: (202) 566-9744. Include docket ID No. EPA-HQOAR-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 Business 
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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-OAR2013-0602. 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 CDROM 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 
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should send a copy of the comment that does not contain the 

information claimed as CBI or otherwise protected. 

 The www.regulations.gov website 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 CDROM 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 
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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. 
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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 Megawatt-hour 

LBNL Lawrence Berkeley National Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 

MWh Megawatt-hour 
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NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

Commissioners 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

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 (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate 

Change 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Executive Summary 

B. Organization and Approach for this Proposed Rule 
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II. Background 

A. Climate Change Impacts from GHG Emissions 

B. GHG Emissions from Fossil Fuel-fired EGUs 

C. The Utility Power Sector 

D. 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
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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 
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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. 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 
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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 fuel-fired EGUs, but also addressing their utilization by 

taking advantage of opportunities for lower-emitting generation 
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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) 

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 
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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 state-specific CO2 goals 

that each state is required to meet, it does not prescribe 

how a state should meet its goal. CAA section 111(d) of 

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 
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policy objectives. Each state can do so alone or can 

collaborate with other states on multi-state 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 
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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 proposalis 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., allowance-trading 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, costeffective strategies that take advantage of investments 

already being made in programs and measures that lower the 
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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 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 emissions1 and 82 percent of U.S. GHG emissions.2 The May 

2014 report of the National Climate Assessment3 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 

 

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 

2

 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. 

3

 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment, May 

2014. Available at http://nca2014.globalchange.gov/. 
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continued increases in impacts across a wide range of 

communities, sectors, and ecosystems. 

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 Memorandum5 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 

 

4

 The President’s Climate Action Plan, June 2013. 

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

climateactionplan.pdf 

5

 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards 
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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 

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 
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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 coal-fired 

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 
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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 
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reductions. 

Both existing state programs (such as RGGI, the California 

Global Warming Solutions program and the Colorado Clean Air, 

Clean Jobs 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 

 

6

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

 

7

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

determine the BSER and to calculate the amount of emission 

reduction achievable through applying the BSER. The state is 

authorized to identify the standard or standards of performance 

that reflects that amount of emission reduction. In addition, 

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

of performance and measures to implement and enforce those 

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

EPA must approve the plan if the standards of performance and 

implementing and enforcing measures are satisfactory. This is 

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

this preamble, as well as in the Legal Memorandum. 
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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 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 improve 

emission rates and to reduce overall CO2 emissions from fossil 

fuel-fired 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 end-use energy efficiency. All of these measures 
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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 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 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 state-specific data used in the 
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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 state-specific 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 
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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 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. 
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The CAA, as interpreted by the courts, identifies several 

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

include technical feasibility, costs, size of emission 

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

implementation and further development of technology). In 

determining the BSER, 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 zeroemitting options. 

As the EPA has done in making BSER determinations in 

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

the types of strategies that states and owners and operators of 

EGUs are already employing to reduce the covered pollutant (in 

this case, CO2) from affected sources (in this case, fossil fuelfired EGUs).8

 Across the nation, many states, cities and towns, 

 

8

 The final emission guidelines for landfill gas emissions from 

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

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

respectively) 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 
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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 

 

practice already being used by some affected sources prior to 

promulgation of the rulemaking.
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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 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 fuel-fired 

EGUs. These measures encompass two basic approaches: 1) 
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reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 

addressing affected EGUs’ mass emissions by varying their 

utilization levels. For purposes of expressing the BSER as 

an emission limitation, in this case in the form of statelevel 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, cost-effective, 

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 
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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 
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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 
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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 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 

 

9

 The 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 coalfired 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. 
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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 
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policy priorities. Consequently, opportunities and 

preferences for reducing emissions, as reflected in each of 

the building blocks, vary across states. While the statespecific goals that the EPA is proposing in this rule are 

based on consistent application of a single goal-setting 

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 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 

state-specific 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 
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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 
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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 ratebased 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
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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 rate-based 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 mass-based 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 statespecific 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 
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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 
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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 tthese 

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 
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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 

than every two years, beginning January 1, 2022, the state 

will be required to compare emission performance achieved 

by affected EGUs 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 
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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 
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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 biennial 

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, 

non-duplicative, 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 
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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 

 

10 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards
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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 componentsand 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 multistate 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 
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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 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 
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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 

website.11 As we and others continue to develop tools, templates 

and other resources, we will update the website. We intend, 

during the public comment period, to work actively with the 

states on resources that will be helpful to them in both 

 

11 www2.epa.gov/carbonpollutionstandardstoolbox. 
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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 
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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 

 

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

the monetary value of impacts associated with a marginal change 

in CO2 emissions in a given year — to analyze 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. 
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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 state-specific basis (referred to as state 

compliance approach), the climate benefits in 2020 are expected 

to be approximately $18 billion (3 percent discount rate, model 
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average, 2011$), 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 cobenefits 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. 

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

NET BENEFITS FOR PROPOSED GUIDELINES IN 2020a

[Billions of 2011$] 

Proposed Guidelines Regional Compliance Approach

 3% Discount rate 7% Discount rate 

Climate benefits b $17 

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

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 

a

 All estimates are for 2020, and are rounded to two significant 

figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 
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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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 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. 

d Total 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. 

e

 The 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 PROPOSED GUIDELINES IN 2030a

[Billions of 2011$] 

Proposed Guidelines Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

Climate benefits b $30 
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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

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

2.1 tons of Hg and 590 tons of HCl 

Ecosystem effects 

Visibility impairment 

a

 All estimates are for 2030, and are rounded to two significant 

figures, so figures may not sum. 
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b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to 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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 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. 

d Total 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. e

 The 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
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greenhouse gases (e.g., nitrous oxide and methane)13 and cobenefits from reducing direct exposure to SO2, NOx and 

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

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

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-years14 in the power 

production and fuel extraction sectors, and we project an 

increase of 78,000 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. 

 

13 Although 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.htm

l

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

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

individual for one year. For example, 20 job-years in 2020 may 

represent 20 full-time jobs or 40 half-time jobs. 
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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 state-specific 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 
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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 sources15, 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

 

15 79 FR 1430
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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 increases the likelihood of heat waves, which are 

associated with increased deaths and illnesses. While climate 

change also increases the likelihood of reductions in coldrelated 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 

 

16 “Endangerment and Cause or Contribute Findings for Greenhouse 

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

66,496 (Dec. 15, 2009) (“Endangerment Finding”).
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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 
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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 
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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 
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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, 

 

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

1.

18 Id., p.138.
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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” 

assessment20 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 

increasesin 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 

 

19 National Research Council, Climate Stabilization Targets, 

p. 3. 

20 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment, May 

2014 Available at http://nca2014.globalchange.gov/. 
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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 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 Fuel-fired 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 

 

21 

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

22 http://www.esrl.noaa.gov/gmd/ccgg/trends/
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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 Sinks23 (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 sinks24 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 

 

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. 

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

forests or underground or deep sea reservoirs of carbon dioxide.

25 From 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. 
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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 fuel-fired 

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

 

26 From 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. 

27 From 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. 

28 From 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. 

GHG EMISSIONS 1990 2005 2012 

 
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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

 

29 U.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 

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

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

Information Administration (EIA) Electric Power Monthly, data 

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 
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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 

 

for December 2013, for the following renewable energy sources: 

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

Available at: 

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

pmt_6_03 
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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 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 EPA has listed more than 60 stationary 

source categories under this provision.32 Once EPA lists a source 

category, 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 

 

31 CAA §111(b)(1)(A). 

32 See 40 CFR 60 subparts Cb – OOOO. 

33 CAA §111(b)(1)(B), 111(a)(1). 
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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 

 

34 CAA section 111(d)(2)(A). 
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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 country36 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 

 

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

36 The EPA is aware of at least four affected sources located in 

Indian Country: two on Navajo lands – the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands – the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 

37 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

38 The most recent amendment was in 77 Fed. Reg. 9304 (Feb. 16, 

2012). 
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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 re-opening them, except that the EPA is 

extending the timetables, as described below. 

Over the last forty years, under CAA section 111(d), the 

agency has regulated four pollutants from five source categories 

(i.e., sulfuric acid plants (acid mist), phosphate fertilizer 

plants (fluorides), primary aluminum plants (fluorides), Kraft 

 

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 Fed. Reg. 

at 53,343. 

40 40 CFR 60.23(a)(1). 

41 40 CFR 60.27(b). 

42 See 40 CFR 60.27(a). 
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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 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 

 

43 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

44 See, e.g., “Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15,372 

(Mar. 21, 2011). 
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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 

 

45 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 
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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. 

 

46 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards
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The 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. 
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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 
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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 states will play in addressing 

carbon pollution from power plants. 

3. Public listening sessions 
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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, faith-based organizations, unions, 

environmental groups, community groups, students, public health 

groups, energy groups, academia and concerned citizens. 

Participants shared a range of perspectives. Many were concerned 

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-HQOAR-2014-0020. 

4. State officials 
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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 multistate 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 
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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. 
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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 one-on-one 

and national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the 

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 
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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 in-depth conversations 

about CAA section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and Regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy, and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 

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 
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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 non-governmental 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 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. 
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 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low cost carbon reductions. 

10. Labor 

EPA senior officials and staff met with a number of labor 

union representatives about reducing carbon pollution 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 AFLCIO headquarters. 
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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 system-wide 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 
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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 
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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 demand-side 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. 
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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 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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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; 

mass-based 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 pricebased 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. 

3. Power plant-specific assessment 
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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. 

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 
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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 non-regulated parties, 

creating a market for emission allowances. This market creates a 

price signal for CO2 emissions, which factors into the dispatch 

 

47 The nine states include Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

and Vermont.
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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 

 

48 Regional Greenhouse Gas Initiative 2013 Allowance Allocation 

http://rggi.org/design/overview/allowance-allocation/2013-

allocation. 

49 Regional Investments of RGGI CO2 Allowance Proceeds, 2012 

(2014), available at http://www.rggi.org/docs/Documents/2012-

Investment-Report.pdf 

50 Of 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-Investment-Report.pdf 

51 Id. 
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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 marketbased 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 

 

52 Regional 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). 

53 The first three-year control period under RGGI, establishing 

CO2 emission limits for EGUs, began on January 1, 2009.

54 RGGI Press Release, January 13, 2014, 

http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.

pdf. 

55 State 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 
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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 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 

 

56 Preliminary 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_Submiss

ion_from_States-FinalCompl.pdf 

57Id.
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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 

 

58 6 New York Codes, Rules & Regulations. Part 251 (Adopted June 

28, 2012). 

59 OR SB 101 (2000); Washington Revised Code ch.80.80 (2013); 

Wash SB 6001 (2007) 
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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 

 

60 Colorado 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_P

rojects/Colorado_Clean_Air_Clean_Jobs_Plan. 

62 http://www.dsireusa.org/ 
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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 

 

63 Report 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
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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 

 

64 Id.

65 Minnesota Statutes 2013, Section 216B.1691, Subdivision 2f. 

Solar Energy Standard 

https://www.revisor.mn.gov/statutes/?id=216b.1691

66 Eugene Water Electric Board Oregon Renewable Portfolio 

Standard 2012 Compliance Report and 2013 – 2030 Implementation 

Plan, June 1, 2013. PacifiCorp's Renewable Portfolio Standard 
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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 fossilfired 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 

 

Oregon Compliance Report for 2012, May 31, 2013. PGE 2012 

Renewable Portfolio Standard Compliance Report, June 1, 2013. 
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by other sources, such as from RGGI CO2 allowance auction 

proceeds mentioned above. 

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 demand-side 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 

 

67 Consortium for Energy Efficiency Annual Industry Report: 2013 

State of the Efficiency Program Industry – Budgets, Expenditures 

and Impacts, 2014. 

68 Lawrence 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) 

69 American Council for an Energy Efficient Economy (ACEEE) 2013 

State Scorecard 

http://www.aceee.org/sites/default/files/publications/researchre

ports/e13k.pdf 

70 December 27, 2013 Letter from Mary D. Nichols, Chairman of 

California Air Resources Board, to EPA Administrator Gina 

McCarthy.
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efficiency and demand reduction resources that are costeffective, 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 Investor-owned 

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 

 

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

72 Cited in December 27, 2013 Letter from Mary D. Nichols, 

Chairman of California Air Resources Board, to EPA Administrator 

Gina McCarthy.

73 Id.

74 Id.

75 State of Vermont Public Service Board, Energy Efficiency 

Utility Creation and Structure. 
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budgets be set at a level to achieve “all reasonably available, 

cost-effective 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 

 

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&Cha

pter=005&Section=00209 

77 Efficiency 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. 
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of energy each year or cumulatively.79 They are typically multiyear 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 investor-owned 

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% 

 

79 State Energy Efficiency Resource Standards: Policy Design, 

Status, and Impacts, D.C. Steinberg, O. Zinaman, NREL Technical 

Report NREL/TP-6A20-61023, April 2014.

80 Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf

81 Id. 
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annually over the 2 year period).82 Utilities can meet the energy 

savings requirements through a variety of means, including costeffective 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. 

 

82 Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf

83 Id. 

84 Arizona Public Service Company 2012 Demand Side Management 

Annual Progress Report, March 1, 2013 website, 

http://www.aps.com/en/ourcompany/aboutus/energyefficiency/Pages/

home.aspx 
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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 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 have, 

the value of regional planning in designing approaches to 

achieve cost-effective GHG reductions. To support state 

flexibility and encourage multi-state 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 
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The EPA is proposing emission guidelines for each state to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction... adequately demonstrated” 

(BSER), and include: 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” (BSER) 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 statespecific 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 
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state would decide whether to 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 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 “best system of 

emission reduction ... adequately demonstrated” (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 of 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 natural gas combined 

cycle (NGCC) units that are under construction). 
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3. Reducing emissions of 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 
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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 which 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, then the state must notify the EPA by 

letter of such intent by no later than April 1, 2016. In this 
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letter, the state must adequately explain why more time is 

needed to submit a complete plan, outline the actions it is 

currently taking to develop a plan and commit to meet all of the 

requirements for an initial submittal by June 30, 2016. A state 

that submits an initial plan with the proper components will 

receive an extension of time to submit a complete plan. 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 multi-state 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 rate-based, 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 
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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. 

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, non-duplicative, 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 
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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 and also achieve its final CO2 emission 

performance level by 2030 and maintain it thereafter. 
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 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. 

B. Summary of Legal Basis 

Today’s 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 fuelfired EGUs. In addition, the EPA recognizes that CAA section 

111(d) applies to sources that, if they were new sources, would 

be covered under a CAA section 111(b) rule. The EPA intends to 

complete two CAA section 111(b) rulemakings regulating CO2 from 

 

85 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands, the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 
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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 BSER;86 accordingly, in this rulemaking, 

the EPA is determining BSER. 

The EPA is proposing two alternative BSER for fossil fuelfired EGUs, each of which is based on methods that have 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, 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 

 

86 The EPA is not re-opening that interpretation in this 

rulemaking. 
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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. 
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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 

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 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 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 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. 
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 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 
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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 
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efficacious means of emission reduction, regardless of whether 

the EPA identifies those measures as part of 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 play 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 
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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).87 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).”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 carbon-dioxide emissions from fossil fuel-fired 

 

87 Pub. L. No. 101-549, § 108(g), 104 Stat. at 2467 (Nov. 15, 

1990).

88 Pub. L. No. 101-549, § 302(a), 104 Stat. at 2574 (Nov. 15, 

1990).
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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 that EPA’s implementing 

regulations define “construction” to include “reconstruction,” 

which the implementing regulations go on to define as the 
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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 
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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-

 

89 In the past, EPA has issued standards of performance under 

section 111(b) and emission guidelines under section 111(d) 

simultaneously. See “Standards of Performance for new Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills – Final Rule,” 61 Fed. Reg. 9905 

(March 12, 1996). 
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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.AB. 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 
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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 

a section 111(d) plan (if it determines that such a plan is 

necessary or appropriate) covering the four potentially affected 

power plants identified above, as well as any subsequently 

 

90 See 40 CFR 49.1 to 49.11. 
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identified similarly situated power plants. The EPA intends to 

take final action on that plan, which will also cover any power 

plants located in U.S. territories, 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 multijurisdictional basis in coordination with nearby states 

developing section 111(d) state plans. The EPA solicits comment 

on such an approach for a federal plan. 
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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 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 

demand-side 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. 

 

91 For 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). 
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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 fuel-fired steam generating boilers as a 

new category subject to section 111 rulemaking, and in 1979 the 

EPA listed fossil fuel-fired combustion turbines as a new 

category subject to the CAA section 111 rulemaking. In the 

ensuing years, the EPA has promulgated standards of performance 

for the two categories, and codified those standards, at various 

times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. In the 

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 
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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. 
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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 
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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 
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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. 

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 emissions reductions that 
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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 

 

92 The 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. 
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 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 re-dispatch 

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 low- or 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 higheremitting 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 
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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 carbon-intensive 

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 

 

93 Elsewhere in the preamble we refer to the potential for 

efficiency improvements to lead to increased competitiveness and 

therefore increased utilization as a “rebound effect.” 
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The first grouping of CO2 emission reduction options that 

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 electricity94

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 co-firing 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 

 

94 For 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. 

95 The 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-coal-fired EGUs. 
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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 

 

96 These 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. 

97 As 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. 
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fossil fuel-fired steam EGUs and integrated gasification 

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 

 

98 CCS already has been or is being implemented at some existing 

EGUs, as noted in the discussion of CCS later in the preamble. 
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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 co-firing 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 cofiring 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 cofiring at an average coal-fired steam EGU would have costs 

 

99 As 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. 
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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 

 

100 The 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. 
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(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 

 

101 Strategies in this grouping also include shifting generation 

from steam EGUs burning oil or natural gas to more efficient 

NGCC units. 
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EGUs,102 making the re-dispatch approach a significantly less 

expensive way to reduce CO2 emissions than conversion or cofiring 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 cofiring, 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 

 

102 This 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. 

103 See Section VI.C.2 below for further discussion. 104 EIA 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. 
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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 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 

 

105 EIA Form 923, available at 

http://www.eia.gov/electricity/data/eia923/. 
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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 re-dispatch 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 redispatch as a CO2 reduction measure have already been developed 

and applied in the industry. Under both RGGI and California’s 

AB32, 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 re-dispatch as an option for 

 

106 Substitution 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. 
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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 
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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 electricitydependent 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 

 

107 See Section VI.C.3 below for further discussion. 
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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 carbonintensive 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. 

 

108 See Section VI.C.4 below for further discussion. 
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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 
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reduction. Additional detail is provided 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 
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 The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 

reduce the carbon intensity of generation at individual coalfired steam EGUs109 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 

 

109 A “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). 
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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 
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coal-fired steam EGUs than for other EGUs, and for purposes of 

determining the best system of emission reduction at this time 

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 

 

110 As 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. 

111 Heat 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.
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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 

 

112 See NEEDSv.5.13 at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html. 

113 A 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. 

114 See chapter 2 of the GHG Abatement Measures TSD for details. 
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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 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 bottom-up 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 
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 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, 
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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 like-kind 

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 

 

115 Temperature data are from the National Oceanic and 

Atmospheric Administration’s Integrated Surface Data, 

http://www.ncdc.noaa.gov/data-access/land-based-stationdata/land-based-datasets/integrated-surface-database-isd. 

Electrical generation data are from EPA’s Air Markets Program 

Data, http://ampd.epa.gov/ampd/. 
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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 

coal-fired 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. 

 

116 We 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. 
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 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 
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a whole, the technical potential for heat rate improvements from 

equipment upgrades incremental to the best-practices 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 coal-fired steam EGU.117 The analysis of 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 

 

117 Electric Power Research Institute 2011 Technical Report – 

Program on Technology Innovation: Electricity Use in the 

Electric Sector (Opportunities to Enhance Electric Energy 

Efficiency in the Production and Delivery of Electricity). 
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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 goal-setting data inputs. However, these 

opportunities would be available as a mechanism for reducing 

carbon-intensity 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 

 

118 As 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.
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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 
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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. The 

study 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 kW-year. 

For a coal-fired EGU with a heat rate of 10,450 Btu per kWh, a 
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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 

 

119 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62 

per MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kWyear. 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 kWyear. 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.
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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 

 

122 $11.63 per metric ton of CO2 * $50 / $100 = $5.81 per metric 

ton of CO2.
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heat rate improvement that can be implemented at a reasonable 

cost.123 

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 coal-fired 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 EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs goes to the achievement of reductions in mass 

 

123 We note that although we expect that heat rate improvements 

are also available from other fossil fuel-fired EGUs, because we 

have less data from which to estimate those improvements we have 

conservatively not included CO2 emission rate reductions for 

those EGUs in the state goals. However, states and sources would 

be free to use heat rate improvements at those other units to 

help reach the state goals.
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emissions at certain affected EGUs – in particular, fossil fuelfired 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 
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EGU owners and grid operators are constantly responding to 

changes in demand and “re-dispatching” to meet demand in the 

most reliable and cost-effective 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 

lower-emitting 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 higher-emitting EGUs, in which 

case grid operators and other market participants would use the 

 

124 The 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_mark

et/2013.shtml. 
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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 loweremitting 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 the 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 
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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 fuelfired 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 coalfired EGUs (as well as oil- and gas-fired steam EGUs) and NGCC 

units. In the short-term – that is, over time intervals shorter 

than the time required to build a new 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 
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as much CO2 per MWh of electricity generated as a typical coalfired 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 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 

 

125 See, e.g., North American Electric Reliability Corp., 2008-

2012 Generating Unit Statistical Brochure – All Units Reporting, 

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

Availability of Gas Turbine Combined Cycle, Power Engineering 

(Feb. 1, 2011), http://www.power-eng.com/articles/print/volume115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html.
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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 redispatch, 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 

 

126 Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990). 
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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 

 

127 The 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. 

128 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 
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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 re-dispatch 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 

 

129 See Section VII for further explanation of how goals were 

computed. 

130 For covered sources. 
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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 re-dispatch 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 

 

131 See 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. 
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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 infrastructure would be capable of 

supporting increased NGCC unit utilization rates is the 

flexibility of the emission guidelines. The state goals do not 

 

132 EIA, Average utilization of the nation’s natural gas 

combined-cycle power plant fleet is rising, Today in Energy, 

July 9,2011, 

http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, Today 

in Energy, Jan. 15, 2014, 

http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent 

data).

133 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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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 

NGCCs. 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 

 

134 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today 

in Energy; INGAA Foundation, Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market (2004 update); INGAA 

Foundation, North American Midstream Infrastructure Through 2035 

- A Secure Energy Future Report (2011). 
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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 

 

135 Pipeline and Storage Infrastructure Requirements for a 30 Tcf 

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

groups confident of 30-tcf market, Oil and Gas Journal, 1999. 

136 For example, between 2010 and April 2014, 118 pipeline 

projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) 

were placed in service, and between April 2014 and 2016 an 

additional 47 pipeline projects with 20,505 MMcf/day of capacity 

(1,567 miles of pipe) are scheduled for completion. Energy 

Information Administration, 

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

137 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

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

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 

138 See Section VII.D and Section VIII below for discussion of 

timing flexibility. 
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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 goal setting 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 
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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 leastcost 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 
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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 re-dispatch 

from higher- to lower-emitting EGUs, and to that end, 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 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 

 

139 See Chapter 3 of the Regulatory Impact Analysis for more 

detail.
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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 higheremitting 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 fuelfired 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 
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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 

 

140 See Regulatory Impact Analysis for more detail.
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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 re-dispatch 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-asusual 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 

 

141 The 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. 

142 To best reflect the integrated nature of the electric power 

sector 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.

143 The 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 
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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 

 

inputs, and results, refer to Chapter 3 of the GHG Abatement 

Measures TSD. 

144 For further explanation of the state goal computation 

methodology, see Section VII of the preamble and the Goal 

Computation TSD. 
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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 re-dispatch 

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 re-dispatch 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. 
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 We also conclude from our analyses that the extent of redispatch 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 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 

 

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

prices at Henry Hub averaged 29.9 percent over the period from 

2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm. 

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

electricity prices averaged 19.5 percent 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. 
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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 below 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 by 

the degree of re-dispatch that can be implemented at reasonable 

cost such that electricity generation could be shifted from more 

carbon-intensive EGUs to less carbon-intensive EGUs within the 

state. 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 
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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 
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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 EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired 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, 

 

147 For 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. 
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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. 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, EPA has 

developed a “best practices” scenario for renewable energy 

generation based on the RPS requirements already established by 

a majority of states. 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 

 

148 Database of State Incentives for Renewables & Efficiency 

(DSIRE), 

http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0. 

149 For discussion of how states and sources might use RE in 

state plans, see Section VIII below. 
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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. 

 

150 EPA recognizes that individual RPS policies vary in their 

specification of where qualifying RE generation must occur. 

However, 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. 
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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, EPA has grouped the states into six regions for 

purposes of developing the best 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 

 

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, EPA has developed RE generation targets for each of 

those states based on the lowest values for the six regions 

evaluated here. 

152 The 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. 
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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 
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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. 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 BSERrelated 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, 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 
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have adopted such requirements. For this purpose, 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 

 

153 See Section VIII below for further discussion of timing 

requirements for state plan submittals. 
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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. 

 Table 6: State RE Generation Levels for State Goal 

Development (Percentage of Annual Generation)154

State 2012 Proposed Goals Alternate Goals 

 

154 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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Interim 

Level * 

Final 

Level 

Interim 

Level * 

Final 

Level 

 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% 
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 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% 
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 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 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 

 

155 In this proposed RE approach, this situation only occurs with 

the RE targets quantified for the state of Washington. 
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corresponding RE generation does not exceed the state’s 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 

 

156 For 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 fuel-fired 

generation was 9.4 TWh. (The 2012 reported RE and fossil fuelfired 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. 
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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 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 
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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 kilowatthour (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

 

157 This 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.

158 Chen et al., "Weighing the Costs and Benefits of State 

Renewable Portfolio Standards: A Comparative Analysis of StateLevel Policy Impact Projections," Lawrence Berkeley National 

Laboratory, March 2007, available at 

http://emp.lbl.gov/publications/weighing-costs-and-benefitsstate-renewables-portfolio-standards-comparative-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.
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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, 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 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 - 

 

160 NREL, “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. 
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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-bystate 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. 

 

162 http://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.
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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 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 

 

163 Lopez et al., NREL, “U.S. Renewable Energy Technical 

Potentials: A GIS-Based Analysis,” (July 2012). 
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alternative approach 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, 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 IPMmodeled 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 

 

164 Additional detail regarding this modeling and approach is 

provided in the Alternative RE Approach TSD. 
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generation for that state would be 600 MWh/year. If the IPMmodeled 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 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 
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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 fuel-fired 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 

 

165 The 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. 
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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 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 
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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 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 
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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 

 

166 Jeffrey Jones and Michael Leff, EIA, “Implications of 

accelerated power plant retirements,” (April 2014). 
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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 at-risk nuclear units to be approximately $12 to 

$17 per metric ton of CO2. 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 underconstruction 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 

 

167 Assuming 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 EPA’s IPM Base Case). 

168 “Nuclear... The Middle Age Dilemma?” Eggers, et al., Credit 

Suisse, February 2013 

169 A state’s historical nuclear fleet is defined as all units in 

commercial operation as of May 2014 with no current plans to 

retire. 
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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 goalsetting computation. If so, how should we do so – for example, 

according to EGU owners’ announcements, the issuance of permits, 

projections of new construction by 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 EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired 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 

 

170 Electricity end-users and electricity end-use referred to 

throughout this subsection include the residential, commercial 

and industrial sectors. 
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 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. 

 

171 Energy Information Administration Form 861, 2012, available 

at http://www.eia.gov/electricity/data/eia861/.

172 See, 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). 
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 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 

 

173 Innovation, Electricity, Efficiency (an Institute of the 

Edison Foundation), Summary of Customer-Funded Electric 

Efficiency Savings, Expenditures, and Budgets (2011-2012) (March 

2013), available at 

http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.as

px. 
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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 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” demand-side energy efficiency scenario. This 

scenario provides an estimate of the potential for sources and 

states to implement policies that increase investment in demandside energy efficiency technologies and practices at reasonable 

costs. It does not represent an EPA forecast of business-asusual 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 fuel-fired 
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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 

 

174 Energy efficiency programs are driven by a variety of state 

policies including energy efficiency resource standards, 

requirements to acquire all cost-effective 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 cost-effective, energysaving upgrades; and processes to certify energy efficiency 

service providers.
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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 standards176 (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, 

 

175 See the appendix to the State Plan Considerations TSD for 

descriptions of the full array of demand-side energy efficiency 

policies currently employed by states. 

176 EERS 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.

177 The 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 
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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. 

 

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

Greenhouse Gas Abatement Measures TSD for more information.

178 E.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. 

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

information on EE program evaluation. 
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Thus, we consider the 1.5 percent annual incremental savings180

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 rate181 to a 

rate of 1.5 percent over a period of years starting in 2017. 

 

180 This 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.
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(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 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 achieved183 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 

 

182 See the Greenhouse Gas Abatement Measures TSD for more 

information. 

183 For 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. 
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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 best-practices 

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 
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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 Scenario185

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% 

 

184 See the Greenhouse Gas Abatement Measures TSD for more 

information.

185 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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 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% 
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 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% 

 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% 

 
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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 costeffectiveness 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 demand-side energy efficiency 
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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 

 

186 Some states do include a valuation of CO2 benefits as part of 

their evaluations of cost effectiveness.

187 E.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/.

188 As 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 
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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 engineering-based, 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 

 

the CO2 emission reduction benefit from the state’s demand-side 

energy efficiency efforts. 
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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 Energy-Efficient 

Economy (ACEEE) surveyed program and participant cost results 

across seven states and found a comparable LCOSE value of 

$54/MWh (2011$).189 

 

189 American Council for an Energy-Efficient Economy (ACEEE), 

The Best Value for America’s Energy Dollar: A National Review of 

the Cost of Utility Energy Efficiency Programs (Report No. 

U1402, March 2014). 
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 To estimate the reductions in power system costs and CO2

emissions associated with the best-practices level of demandside energy efficiency described above, the EPA analyzed a 

scenario incorporating the resulting reduction in electricity 

demand and compared the results with the business-as-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. 
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 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. 
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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 

carbon-intensive 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 
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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 coal-fired 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. 
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 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 cofiring 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 
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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 cofiring economically attractive in some circumstances. One 

example is that natural gas reburn strategies that involve cofiring 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 non-catalytic 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-
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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 cost-effective, 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 cobenefits 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 storage190 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 

 

190 This is also sometimes referred to as “carbon capture and 

sequestration.”
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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 
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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 
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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 carbonintensity affected EGUs with lower-carbon generation from 

existing NGCC units.191 From a technical perspective, the same 

potential would exist to replace high-emitting 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 

 

191 For purposes of this proposal, NGCC units that have commenced 

construction as of January 8, 2014 are “existing” units. 

192 Whether 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 

carbon-intensive existing EGUs. Because the proposed state goals 

also reflect the opportunity to reduce utilization of high 

carbon-intensity EGUs by shifting generation to less carbonintensive 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. 
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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 
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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 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 
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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 
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steam EGUs, gas-fired 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/gasfired 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. 
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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 carbonintensive affected EGUs in the amount that results from 

substituting generation at those EGUs with generation from 

 

193 For 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. 
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less carbon-intensive 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 zero-carbon 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 
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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. 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. 
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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 
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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 
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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 emission 

reductions achievable with the support of the combination of all 

four building blocks satisfies 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 
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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 emissions performance level, in turn, 

constitutes the minimum degree of stringency for the standards 

of performance, taken as a whole, that 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 
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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 are 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, 

higher-emitting 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 
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discusses characteristics of the electricity industry relevant 

to 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 
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BSER. In subsection 9, we discuss how the BSER and the statewide 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. 
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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 

 

194 Portland 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). 

195 As 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,” 
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 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 

 

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. 

196 See 1970 Senate Committee Report No. 91–1196 at 15 (“The 

maximum use of available means of preventing and controlling air 

pollution is essential to the elimination of new pollution 

problems”). 

197 See 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”). 

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

standard of performance designed to promote the use of an 

emerging technology). 
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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 

 

199 See Train v. Natural Res. Def. Council, 421 U.S. 60 (1975). 
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(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 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. 

 

200 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 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 Fed. Reg. 9905 

(Mar. 12, 1996). 

201 See, e.g., “Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15372 (Mar. 

21, 2011). 
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 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 
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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 capand-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 
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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 

 

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. 
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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 

 

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 Cross-State 

Air Pollution Rule (76 FR 48208, Aug. 8, 2011). 

204 A number of utilities also have climate mitigation plans. 

Examples include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 
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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 sourcelevel 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 

 

205 State of California Global Warming Solutions Act of 2006, 

Assembly Bill 32, http://www.leginfo.ca.gov/pub/05-

06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf. 

206 December 27, 2013 Letter from Mary D. Nichols, Chairman of 

California Air Resources Board, to EPA Administrator Gina 

McCarthy. 

207 See 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_pl

an.pdf. 
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emission allowances also impacts hourly dispatch decisions; 

where emission allowance requirements are in effect, EGU owners 

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 higheremitting 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 low- or non-emitting energy plants or with end-use 

 

208 The requirement to hold allowances covering their CO2

emissions went into effect for EGUs in California on January 1, 

2013. 

209 The 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. 
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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 States211 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 

 

210 See State of Colorado House Bill 10-1365, available at 

http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0

CA296732C8CEF4D872576E400641B74?Open&file=1365_ren.pdf. 

211 Participating states include Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

and Vermont. 
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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 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 

 

212 See RGGI website at http://www.rggi.org/rggi. 
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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 longer-term 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 

 

213 Potential 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. 
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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 
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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 undertake 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 
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Section VI.C.1 above. We consider heat rate improvement to be a 

common and well-established practice within the industry. 

 Other BSER criteria also favor building block 1 as a 

component of the BSER. For example, with respect to non-air 

health and environmental impacts, heat rate improvements cause 

fuel to be used more efficiently, reducing the volumes of and 

therefore the adverse impacts associated with disposal of coal 

combustion solid waste products. 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 
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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 carbon-intensive 

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 higher-emitting 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.” 
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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 
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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 carbon-intensive 

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 carbonintensive affected sources to reduce emissions as much as 

possible so as to reduce their need to purchase allowances (or 

to allow them to sell un-needed 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. 
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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 – 

 

214 According to a DOE/NETL study, the relative amount of water 

consumption for a new pulverized coal plant is 2.5 times the 

consumption for a new NGCC unit of similar size. “Cost and 

Performance Baseline for Fossil Energy Plants: Volume 1: 

Bituminous Coal and Natural Gas to Electricity,” Rev 2a, 

September 2013, National Energy Technology Laboratory Report 

DOE/NETL-2010/1397. 

215 For purposes of this rulemaking, “existing” EGUs include 

units under construction as of January 8, 2014, the date of 

publication in the Federal Register of the Carbon Pollution 

Standards for new fossil fuel-fired EGUs. 
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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 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 

 

216 Because building blocks 3 and 4 reduce generation and CO2

emissions from all fossil fuel-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. 
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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 zero-carbon generating capacity – is a 

component of the BSER because the expansion and use of renewable 
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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, well-established 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 re-dispatch, 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 
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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 
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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 

 

217 See 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, closedcycle 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 
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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 fuel-fired 

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, 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 

 

Water Management R&D Program, available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysi

s/Publications/PowerPlantWaterMgtR-D-Final-1.pdf. 
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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 demandside 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 demand-side 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 
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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 
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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 
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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 coalfired 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 
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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 coalfired 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 

 

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. 
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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 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 wellestablished. The combination of all four building blocks would 
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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 

 

219 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2, 

indicating that the addition of building block 2 would mitigate 

the potential concern about a “rebound effect” if building block 

1 were implemented in isolation, applies to the combination of 

all 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. 
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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 

demand-side 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 
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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 cost-effective measures (notably demand-side energy 

efficiency). The EPA considers this analysis strong confirmation 

of the reasonableness of the costs of the measures in the 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. 
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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 
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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 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 

 

220 Oxford Dictionary of English (3rd ed.) (published 2010, 

online version 2013), 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. 
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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 

 

221 CAA §101(a)(3), (c). 

222 For 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.) 
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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 re-dispatch 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

 

223 CAA §401(b), 404(f)-(g). 

224 See 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 
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 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. 

 

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 energy-efficiency programs and 

renewable energy generation may fit within the §111 framework, 

however, because both reduce the utilization of power plants .... 

According to this reasoning, emission reductions are occurring 

within the source category, because of changes in generation at 

the power plant.”). 

225 Ceronsky 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_actstrong_flexible_costeffective_carbon_pollution_standards_for_existing_power_plants.p

df; 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). 
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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 pre-existing 

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 
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modern types of generation, as well as shorter-term 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, co-firing, 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 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. 

 

226 http://online.wsj.com/article/PR-CO-20140508-915605.html. 
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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 

unit-specific 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 longerterm 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 

compliance 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, 
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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 coalfired EGUs can implement efficiency improvements as well as 

 

227 For examples, see Large Public Power Council, Energy 

Efficiency Working Group, Second Annual Energy Efficiency 

Benchmarking Report (2013); https://www.nreca.coop/nreca-on-theissues/energy-operations/energy-efficiency/. 
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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 long-term 

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 

 

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

from Electric-Sector Energy Efficiency and Renewable Energy 
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8-hour ozone NAAQS SIPs that were due in 2007; for example, 

Washington, D.C., included the purchase of wind power and the 

installation of LED traffic lights229; 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 guidance232 and has partnered with NESCAUM and three 

states (Maryland, Massachusetts, and New York) to identify 

 

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/pubdocuments/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. 

231 CT 1997 8-hour ozone SIP website, 

http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1

619 (see Attainment Demonstration TSD, Chapter 8 at 31, 

http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_rep

orts/section_8.pdf). 

232 Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs (July 2012), 

http://epa.gov/airquality/eere/manual.html. 
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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 fuels 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 

 

233 States’ Perspectives on EPA’s Roadmap to Incorporate Energy 

Efficiency/Renewable Energy in NAAQS State Implementation Plans: 

Three Case Studies, Final Report to the U.S. Environmental 

Protection Agency (Dec. 2013), 

http://www.nescaum.org/documents/nescaum-final-rept-to-epa-eein-naaqs-sip-roadmap-case-studies-20140522.pdf. 
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assumptions consider re-dispatch to NGCC units, they do not 

consider re-dispatch beyond the NGCC capacity already existing 

in a state. In that way, the proposal does not presume that 

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 higher-emitting 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 
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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 
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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 

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 carbon-intensive 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 

 

234 See the discussions of California AB32 and RGGI above in this 

section and elsewhere in the preamble. 
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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. 
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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 

 

235 Across 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. 

236 http://www.isorto.org/Documents/Report/20140128_IRCProposalReliabilitySafetyValve-RegionalComplianceMeasurement_EPAC02Rule.pdf. 
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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 re-dispatch, 

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 provisions of 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 
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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, 

 

237 Commenters have critiqued this “at-the-unit” and “beyond-theunit” distinction as follows: 

There is an argument that the at-the-unit/beyond-the-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 

at-the-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 enduser 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 highemission generation with lower emission generation, fuelswitching, heat-rate improvements, etc.—are effectively atthe-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 atthe-unit systems of emission reduction, the at-theunit/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 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). 
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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 reduction 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 
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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 EUGs 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 

above-discussed definition of “system,” reduced generation is a 

“set of things” – which include reduced use of generating 

equipment and therefore reduced fuel input – that the affected 

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 

 

238 For this reason, under a Chevron step 1 interpretation, 

“system of emission reduction” includes reduced generation. 

239 For these reasons, under a Chevron step 2 interpretation, 

“system of emission reduction” includes reduced generation. 
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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 well-established 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 

 

240 See 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. 

241 See, 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/wisconsinpo

wer-cd.pdf.
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well as the transport rules that we refer to as the NOx SIP 

Call242 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 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 business 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 

 

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

243 70 FR 25162 (May 12, 2005). 
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important for continued emissions reductions. All these results 

come about because the operation of the electrical grid through 

integrated generation, transmission, and distribution networks 

creates fungibility for electricity and electricity services, 

which allows decreases in generation at affected fossil fuelfired 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 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 
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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 demandside energy efficiency programs, as also discussed above.245

Third, as also discussed above, regional entities in the 

electricity system can accommodate these substitutes. 

 

244It 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. 

245 The nuclear generating capacity reflected in building block 3 

is already in operation or under construction. 
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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. 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 
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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 
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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 zero-carbon 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 near- and 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] long-term national and regional impacts,” and by 

“using a long-term lens with a broad focus on future costs, 
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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 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 

 

246 Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981). 
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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 subsection. 

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 
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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 coal-fired 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 
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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 
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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 
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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 meets this 

 

247 See 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”). 
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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 
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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. 

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 
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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 fuel-fired EGUs, both as 

identified above and as further discussed in the Legal 

Memorandum in the docket.248 In particular, we invite comment on 

 

248 However, as noted, we are not soliciting comment on issues 

that were resolved by the implementing regulations. 
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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 
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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 statespecific, adjusted249 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 

 

249 As 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. 
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translated goal achieves the same degree of emission 

limitation.250 

 The EPA is also proposing that measures taken by a state or 

its sources 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, 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 

 

250 A method for translating from a rate-based goal to a massbased goal is discussed in the Projecting CO2 Emission 

Performance in State Plans TSD. 
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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 coal-fired 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 
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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 
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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 
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Power Plant, on Ute tribal lands within Utah.251 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.252 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. 

 

251 The South Point facility is an NGCC power plant, and the 

Navajo, Four Corners, and Bonanza facilities are coal-fired 

power plants. 

252 As 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. 
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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-weighted-average CO2 emission rates that the affected 

fossil fuel-fired EGUs located in each state could achieve, on 

average, through application of the measures 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 
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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 state-specific 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 
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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 state-specific 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 
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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 coal-fired EGUs, to EGUs with lower CO2 emission rates, 

such as NGCC units. Our analysis indicates that shifting 

generation among EGUs offers opportunities to achieve large 

amounts of CO2 emission reductions at reasonable costs. 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-weightedaverage emission rates in order to accommodate reduced 

utilization of affected EGUs associated with measures such as 

increases in low- and zero-carbon generating capacity and 

demand-side energy efficiency. We recognize that these measures 

support reduced overall CO2 mass emissions from affected EGUs 
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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 ratebased 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

emissions253 rather than on CO2 emission rates, because the 

 

253 We also recognize that even under a mass-based 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. 
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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 output254 – 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.255 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 

 

254 As 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. 

255 For some EGUs, total net or gross energy output also includes 

useful thermal output, in addition to either net or gross 

electric energy output. 
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EGUs report gross rather than net load256 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 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 

 

256 Some EGUs report gross steam output instead of gross 

electrical load. 
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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 output-weightedaverage 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, 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.) 
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Table 8: Proposed State257 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired 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 

 

257 The 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, EPA 

is not proposing goals for Indian country or U.S. territories at 

this time. 
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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 
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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 outputweighted-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. 
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The adjustment is made by estimating the annual net generation 

associated with an achievable amount of qualifying new lowcarbon 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.258 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 

 

258 In the case of new capacity that is not zero-carbon, an 

adjustment would also be required to the emissions value used in 

computing the weighted-average emission rate. This procedure is 

discussed further in the Goal Computation TSD. 
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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.259 For each state, we aggregated the 2012 data 

for all coal-fired steam EGUs as one group, all oil- and gasfired steam EGUs as a second group, and all NGCC units as a 

third group. 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.260 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 

 

259 EGUs 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 turbines were excluded on this basis. See the 

applicability criteria described in Section V.B. above. 

260 The 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. 
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emission guideline.261 Capacity and emission rate data inputs for 

the post-2012 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 

 

261 Assuming 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). 
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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/gasfired steam EGU groups from Step 2 were proportionately262

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 fuel-fired 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.263 

 Step 4 (application of building block 3). We estimated the 

total quantities of generation from renewable generating 

 

262 For 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 carbonintensive NGCC group would be split equally between the coalfired steam group and the oil/gas-fired steam group. 

263 We 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. 
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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 

under-construction 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 demandside 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 
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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 

output-weighted-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.264

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. 

 

264 Expressed as a formula, the equation for the annual rate 

computation is: 

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

emission rate) + (NGCC gen. x 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. 
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 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 
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historical data to which 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 coal-fired 

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 electricity-importing states described in Step 5. We 

also request comment on the alternative of making no adjustment 
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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 massbased form of goal; and (iii) the opportunity to pursue multistate 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 
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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 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 multiyear 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. 
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 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 mass-based 

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 mass-based Regional Greenhouse Gas 

Initiative (RGGI) may choose to develop state plans (or a multistate 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 massbased 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 multistate 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 RGGI-participating states 
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could choose to submit a multi-state mass-based plan that 

demonstrates emission performance by affected EGUs on a multistate basis. Additional states may also choose to join a multistate plan. The mechanics of translating rate-based goals into 

mass-based 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.265 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 

 

265 40 CFR 60.22(b)(5). We do not propose to re-open that portion 

of the implementing regulations in this rulemaking. 
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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.266 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 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 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.267 To reiterate, the 

proposed state goals represent the level of performance that is 

achievable through application of the BSER to the pertinent data 

 

266 Id. 

267 Id. We do not propose to re-open that portion of the 

implementing regulations in this rulemaking. 
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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 
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provision for state adjustment of goals outside the normal 

notice-and-comment rulemaking process is warranted.268

E. Alternate goals offered for comment and other approaches 

considered 

 In addition to the proposed state-specific emission ratebased 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 

 

268 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). 
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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 phasein 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 State269 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,270 1,237 

Alaska 1,170 1,131 

Arizona * 779 763 

 

269 See footnote accompanying Table 8 above. 
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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 

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 
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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 
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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 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 
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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 multi-state 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 carbonintensive EGUs. A potential advantage of using regional 

evaluations is the ability to recognize additional emission 
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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 goal-setting 

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. 
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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 
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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 carbonintensive 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 
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that state’s energy profile and economy, as long as the state 

achieves the reductions necessary to meet its goal. Many marketbased 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. 

Multi-state 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 end-use 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 
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adequacy.270 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 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 

 

270 See the Resource Adequacy and Reliability Analysis TSD, 

available in the docket. 
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support that economy. The EPA welcomes comments and suggestions 

on this issue. 

VIII. State Plans 

A. Overview 

After the EPA establishes the state-specific 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 ratebased 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 
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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, 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.271 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, 

 

271 See 40 CFR 49.1 to 49.11. 
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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 state-specific 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 
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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 
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example, the RGGI states’ implementation of their mass-based 

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 reductions at 

the affected sources, we believe that different types of state 
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plans could be constructed that make use of the diversity of 

measures available to achieve CO2 emission reductions. Based on 

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 demandside 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 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. 
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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 
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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 fuel-fired 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 fuelfired 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 
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with other enforceable measures, such as RE and demand-side EE 

measures, that reduce CO2 emissions. 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 utility-driven 

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 
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RE and demand-side EE measures that avoid EGU CO2 emissions.272

Under a state-driven approach, the measures in a state plan 

would include emission standards for affected EGUs, as well as 

requirements that apply directly to entities other than affected 

EGUs, for example, renewable portfolio standards (RPS) or enduse energy efficiency resource standards (EERS), both of which 

often apply to electric distribution utilities.273

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. 

 

272 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.

273 A 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.
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We note that some existing state programs, such as RGGI in 

the northeastern states, do impose the ultimate responsibility 

on fossil fuel-fired 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 emission rates 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 
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level of required emissions 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 
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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 wellestablished, 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 
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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 
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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 
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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 that is a reasonable construction of the 

statute.274 

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 

 

274 Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 842-44 (1984) 
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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 section 111 as 

allowing state 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 once approved into the 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 EGU’s 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 fuel-fired EGUs where such standards 

result in reduced CO2 emissions from fossil fuel-fired EGUs, even 
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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 demandside 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, 
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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 
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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 state level 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 
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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 
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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 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, 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 
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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 massbased 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). 
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The EPA invites comments on this interpretation of 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 forwardlooking, longer-term 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 
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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. Following are proposals for: a) 

state plan performance demonstrations, b) the start date for the 

interim goal performance period, c) the duration of the 

performance periods for the final and interim goals, d) interim 

progress milestone requirements, e) consequences if actual 
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emission performance does not meet the state goal, and f) outyear requirements for states to maintain CO2 emission performance 

levels over time consistent with the final goal. In Section 

VIII.B.2.f, the agency also requests comment on alternative 

requirements aimed at continued emission performance improvement 

after 2029. In Section VIII.B.2.g, 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 5) 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 state-specific 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 
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ensure that their plans achieve the goals as intended. As a 

result, the agency envisions that the EPA, states, and regulated 

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 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. 
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 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.275 

 

275 The 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 BSER-based 
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 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.276 This date would 

 

level is a more stringent level than the 2020-2029 average fourbuilding-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.

276 The 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 
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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 

 

would recompute the state goals consistent with the selected 

start date.
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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 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. 
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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 leastcost 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.277 In addition, the existing natural gas 

pipeline and electricity transmission networks are already 

connected to every existing NGCC facility, and can support 

 

277 Source: NERC, 2008-2012 Generating Unit Statistical Brochure 
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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 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 
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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 
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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 state-specific 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 5) 

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. 
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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 
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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 

output278 from affected EGUs over the 10-year performance period, 

with rate adjustments for qualifying 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 

 

278 For EGUs that produce both electric energy output and other 

useful energy output, there would also be a credit for nonelectric output, expressed in MWh.
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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 “self-correcting” in that they 

inherently would assure interim performance and full achievement 

of the state plan’s required level of emission performance 

through requirements that are enforceable against affected EGUs. 

One example is a state plan with a rate-based emission 

performance level that requires affected EGUs collectively to 

meet an emission rate consistent with the state’s required 

emission performance level, and allows EGUs to comply through an 

emission rate averaging system. Another example is a plan that 
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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 “self-correcting.” 

 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 EPA, explain the cause, and describe the 

steps the state will take to accelerate subsequent 
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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 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 year. 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 
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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 
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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 
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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, 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 
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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 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 greaterthan-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 
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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 sulfur dioxide program; 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. 

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 
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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 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 intended the emission 

performance improvements required under CAA section 111(d) to be 

permanent. 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. 
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 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, 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.279 After 

implementation, the state would be required to compare actual 

plan performance against the final goal on a rolling three-year 

 

279 This 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. 
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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 pre-implementation 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 BSER-based 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 
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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 mass-based and rate-based goals 

after 2029 

 The EPA proposes that states have flexibility to choose 

between a rate-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 economic 

growth after 2029. The state either could adopt a rate-based 

performance level consistent with the final goal, or could adopt 
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a new mass-based performance level based on a translation of the 

rate-based final goal to a mass-based 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 6. 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 5.

 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 threeyear 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. 
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 In connection with the alternative state goals, for the 

years after 2027, the EPA requests comment on the same “outyear” issues and concepts for maintaining or improving emission 

performance over time that are described above in Section 

VIII.A.2.e. The EPA requests comment on whether state plans 

should provide for emission performance after 2025 solely 

through post-implementation emission checks that do not require 

a second plan submittal, or a whether states 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 
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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.280 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 

 

280 Flexibilities provided to states in meeting this general 

approvability criterion are discussed below in Section 

VIII.C.2., emission performance.
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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.281 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. 

 

281 Enforceability 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.”
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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.282 

The EPA recognizes that a portfolio approach may result in 

enforceable state plan obligations accruing to a diverse range 

 

282 This 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.
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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 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 
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affected EGUs. As a result, the EPA is not proposing that outof-sector GHG offsets could be applied to demonstrated 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, project-based 

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 
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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.
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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 ratebased 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 
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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.283

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 

 

283 Considerations 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. 
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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 abovein 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 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 

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 C.F.R. 60.23–60.29, except as specified otherwise by these 

emission guidelines. These requirements apply both to individual 

state plans and multi-state plans. 
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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 multistate plan. These options might also address contingencies 
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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 multi-state 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 statespecific 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 multi-state 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-
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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: 

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 rate-based CO2

emission goal identified for the state in the emission 
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guidelines or a translation of the rate-based goal to a massbased goal. 

A state plan must identify the rate-based 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, 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 
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plan achieve a weighted average CO2 emission rate that is 

consistent, in aggregate, with an aggregation of the statespecific rate-based 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 mass-based goal would be based on 

translation of an aggregation of the state-specific 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, rate-based emission performance 
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goals. However, it does not address the fact 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 ratebased emission performance goals for the participating states or 

the requirements, programs, and measures included in the multistate 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-
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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 mass-based 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 mass-based 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 
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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 ratebased 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 
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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 
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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 self-correcting 

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 
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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 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 mass-based standard. We also solicit comment on 

longer and shorter averaging times for emission standards 

included in a state plan. 
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8. Demonstration that each emission standard is quantifiable, 

non-duplicative, 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.284 This guidance serves as the 

foundation for the types of monitoring, reporting, and limits 

that 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 

 

284 EPA guidance on enforceability includes: (1) September 23, 

1987 memorandum and accompanying implementing guidance, “Review 

of State Implementation Plans and Revisions for Enforceability 

and Legal Sufficiency,” (2) August 5, 2004 “Guidance on SIP 

Credits for Emission Reductions from Electric-Sector Energy 

Efficiency and Renewable Energy Measures,” and (3) July 2012 

“Roadmap for Incorporating Energy Efficiency/Renewable Energy 

Policies and Programs into State and Tribal Implementation 

Plans, Appendix F.” 
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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 non-duplicative 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 multi-state plan. This does not 

mean that measures in an emission standard cannot also be used 
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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. 
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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 Sections 113(a)–(h) of the CAA. 
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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 
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would be to require use of the most accurate RATA 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 multiEGU 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-to-electric energy conversion calculation as provided 
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in the proposed EGU GHG NSPS regulations.285) We solicit comment 

if EGUs producing both electric energy output and useful thermal 

output should 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 GHG NSPS regulations for new, modified, and 

reconstructed sources, we invite comment here on a range of twothirds to 100 percent credit for useful thermal output in the 

final rule, or other alternatives to better align incentives 

with avoided emissions. 

 

285 70 FR 1429-1519; January 8, 2014.
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 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.4 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 
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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 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 
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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. 

The EPA is also 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 
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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. 

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 
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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 that 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), that 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 
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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 multistate plan, the EPA is proposing that only one multi-state 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 multistate 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 EPA specifies 

otherwise.286 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 

 

286 40 CFR 60.23(a)(1). 
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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 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 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 
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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.287 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 

 

287 This update would only apply to states that receive a twoyear extension for the submission of a complete plan, by June 

30, 2018.
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effort to precisely demonstrate sources of 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. 
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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 standards, unitspecific 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 
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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. 
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For states participating in a multi-state program, the 

initial submittal should include executed agreements among the 

participating states and a road map for both design of the 

multi-state program and its implementation at the state level. 

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”.288 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.289 The MOU also included a commitment to 

launch the program by January 1, 2009 in all states and 

 

288 Regional 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.

289 The 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. 
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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 marketbased 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. 
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After receipt of a complete plan submittal, 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 Act. The 

framework regulations currently provide for EPA to act on a 

complete plan within four months. 40 CFR 60.27(b). The EPA 

proposes that for plans under this guideline, 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 this guideline, the 

agency may use two approval mechanisms provided for in sections 

110(k)(3) and (4) of the CAA, 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 

section 110 for agency actions on state implementation plans. 
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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 the 

guideline. 

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 this 

guideline, 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 the 
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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. 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 this guideline, 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 
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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, 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 
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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. 
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 The EPA is also seeking comment on whether it should 

provide for, or require, electronic submittal of initial and 

complete plans. It is 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 EPAstate 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 a state’s policy 

objectives and is approvable by the EPA. In this section, we 
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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. 
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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 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. 
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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.290

The agency recognizes that states that have already shifted 

toward lower carbon-intensity generation or ramped up demand-

 

290 For 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.
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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 demand-side 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,291 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 

 

291 An “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.
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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.292 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 

 

292 We 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.
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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 
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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 forward-looking 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 goal-setting 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. 
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The EPA also solicits comment on a second broad option. 

This option would recognize emission reductions that existing 

state requirements, programs 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 
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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 forwardlooking method that the EPA has proposed for establishing state 

goals based on the application of the BSER. 
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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 rate-based 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 rate-based 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-the-books energy efficiency resource 
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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 

mass-based 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 ratebased 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 
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rate.293 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 EGUs294 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

 

293 We are also proposing that RE and demand-side 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.

294 This could include an individual affected EGU or group of 

affected EGUs if a rate-based averaging or trading approach is 

used.
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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 

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.295 In practice, the average or 

marginal CO2 emission rate in the power pool or identified region 

 

295 As 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.
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– 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-
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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 demandside 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. 
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Utilities and states have conducted ongoing EM&V of demandside 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 energy 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 welldefined 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,”296 where appropriate, for well-

 

296 Deemed savings are measure-specific stipulated values based 

on historical and verified data. Unlike other EM&V approaches, 
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understood 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,297 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 

 

deemed savings approaches involve limited or no measurement 

activities, and are therefore a common and relatively low-cost 

strategy for documenting energy savings. 

297 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.
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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 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 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 
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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.298 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.299 The EPA’s goal 

in developing such guidance is to assure that it is consistent 

with industry-standard EM&V approaches for both RE and demandside 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. 

 

298 Section 4 of the State Plan Considerations TSD includes a 

detailed description of these EM&V parameters.

299 A list of these protocols is provided in Section 3.1 of the 

State Plan Considerations TSD.
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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 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 demandside 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 demandside 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 
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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, EPA is 

requesting comment on whether guidance should limit 

consideration to certain well-established programs, such as 

those characterized in Section 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 rate-based approach or implements a mass-based portfolio 
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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 demandside EE measures under the utility plan would be necessary to 

demonstrate emissions 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 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 
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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 demand-side 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
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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 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 multi-state 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 demandside 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 
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contiguous electric grid region, in which case attribution of 

emission reductions demand-side EE 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 double-counted 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

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-
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state plans could distribute the CO2 emission reductions among 

states in the multi-state area, as long as the total CO2 emission 

reductions claimed are equal to the total of each state’s instate 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 
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the plan will include a translation of the rate-based 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 
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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 costcontainment 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 multisector in nature, regulating emissions for source categories in 

addition to EGUs. As a result, emission projections in state 
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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 massbased 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 model.300 This 

latter approach would be able to capture dynamic interactions 

within the electricity sector, based on system operation and 

 

300 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.
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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 
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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 meets the proposed criteria for 

approvable state plans could be employed in a state plan. Beyond 

that, any measure that reduces affected EGU emissions – even if 

not included in the state plan -- will, if implemented during 

the compliance 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 
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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 biomassderived 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 BSER, the agency 

anticipates that some states may be interested 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. 
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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 cofiring 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 compliance demonstration as a 

reduction in the emission rate at a fossil-fuel-fired unit 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 were 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 
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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 baseline 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 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 
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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 

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-
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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 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 
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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 

section 111(d), 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 fossil 

plants, so can transmission upgrades. 
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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 discussion in the subsection, the EPA 

intends to make additional technical resources available, and 

consider guidance. to states should they need such support in 
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exploring and adopting these options the EPA, in addition, takes 

comment on whether there are still other areas beyond those 

discussed above for which it would be useful for 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 biomass-derived 

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, 
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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 

biomass-derived 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 

circumstances in which biomass is grown, harvested and combusted 
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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 biomass-derived 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.” 
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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.301 The agency also requests comment 

on whether it would be desirable to include in regulatory text 

any aspects of this analysis preamble discussion about how the 

provisions in the existing implementing regulations concerning 

source-specific factors relate to in regulatory text of 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 

 

301 The agency is not reopening or considering changes to this 

provision of the implementing regulations. 
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The EPA’s 1975 implementing regulations302 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 

 

302 40 CFR Section 60.24(f) 
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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 this emission guidelines 

In general, the EPA notes that the implementing regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 

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 
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pulp plants specify emission limits for sources.303 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. 

 

303 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

 
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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 facilityspecific issues, the state is free to make adjustments to a 

particular facility’s requirements on facility-specific grounds, 

so long as any such adjustments are reflected (along with any 

necessary compensating emission reductions), 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 statespecific 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 
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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 expenditures304

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 

 

304 The 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.
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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 that 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 sourcespecific 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 
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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).305 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 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 

 

305 Heat rate improvement methods and related capital costs are 

discussed in the GHG Abatement Measures TSD; SO2 scrubber capital 

costs are from the documentation for EPA’s IPM Base Case v5.13, 

Chapter 5, Table 5-3, available at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html
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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 
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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,306 and (ii) must “be treated as a 

standard of performance” for purposes of, in general, the CAA.307

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 applies to state plans under CAA section 111(d).308

We invite consideration of the proper interpretation of CAA 

sections 111(d) and (h), under either Chevron step 1 or step 2, 

 

306 CAA section 111(h)(4). 

307 CAA section 111(h)(5). 308 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). 
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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 be revise 

their plans accordingly without further rulemaking from the EPA? 

11. Emissions averaging and trading 
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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).309 The term “standard” in the phrase “standard for 

 

309 Typically, in a mass emission limit trading program, sources 

are required to obtain an allowance for each measure (e.g., ton) 
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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.’”310. 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. 

 

of air pollutant they emit. The acid rain program under Title IV 

of the CAA is an example of this type of trading program. 

310 Engine 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)) 
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 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.311

G. Additional Factors That Can Help State Meet Their CO2 Emission 

Performance Goals 

A resource available from the EPA for states pursuing marketbased 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 marketbased 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 

 

311 See “Standards of Performance for New and Existing Stationary 

Sources: Electric Utility Steam Generating Units, Final Rule,” 

70 Fed. Reg. 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 Fed. Reg. 65,387 (Dec. 19, 1995) (trading rules 

codified in 40 C.F.R. §§60.33b(d)(1)-(2)).
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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 
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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 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,”312 as well 

as the State Energy Efficiency Action Network’s “Energy 

Efficiency Program Impact Evaluation Guide.”313 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 website: 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. 

 

312 http://epa.gov/airquality/eere/

313 http://www1.eere.energy.gov/seeaction/index.html

http://www1.eere.energy.gov/seeaction/pdfs/emv_ee_program_impact

_guide.pdf
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For the final rulemaking, the EPA plans to organize 

resources on the website 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,314 National Action Plan for Energy 

Efficiency (Action Plan),315 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 website 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 

 

314 Appendix, State Plan Considerations TSD

315 http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html
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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) 
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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 
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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 
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the dispatch enough to result in a significant net emissions 

increase that would trigger NSR (effectively establishing a 

synthetic minor limit). 316

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 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. 

 

316 Certain stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements. 

See, e.g., CAA §§ 165(a)(1), 169(1), 501(2), 502(a). A synthetic 

minor limitation is a legally and practicably enforceable 

restriction that has the effect of limiting emissions below the 

relevant level and that a source voluntarily obtains to avoid 

major stationary source requirements, such as the PSD or title V 

permitting programs. See, e.g., 40 CFR §§ 52.21(b)(4), 

51.166(b)(4), 70.2 (definition of “potential to emit”). 
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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 
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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 re-visiting 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 
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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.317 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 oil-fired 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 

 

317 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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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).318 This rule 

includes 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.319 The 316(b) 

rule subjects existing power plants and manufacturing facilities 

 

318 The pre-publication version of the final rule is available 

at: http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/#final 

319 CWA section 316(b) provides that standards applicable to 

point sources under sections 301 and 306 of the Act must require 

that the location, design, construction and capacity of cooling 

water intake structures reflect the best technology available 

for minimizing adverse environmental impacts.
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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 control requirement that limits 

the number of fish destroyed through impingement, as well as 

site-specific entrainment mortality standards. Certain plants 

that withdraw very large volumes of water will also be required 

to conduct studies for use by the permit authority in 

determining the site-specific entrainment mortality standards 

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 exercise best professional judgment in 

establishing appropriate site-specific standards, taking into 

account, among other factors, compliance costs, facility 

reliability and grid reliability. Existing sources subject to 

the 316(b) rule are given until [INSERT DATE] (i.e., eight years 

from the rule's effective date) to comply with the rule's 

impingement standards. They must comply with applicable sitespecific entrainment mortality standards 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 existing 
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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. 
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 On June 21, 2010 (75 FR 35128), the EPA proposed the CCR 

rule, which co-proposed 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.320 While the EPA still is evaluating all the available 

 

320 Beneficial 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 
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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, 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.321 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 

 

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). 

321 U.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 

 
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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 
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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.322

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 

 

322 It should be noted that regulatory obligations imposed upon 

states and sources operate independently under different 

statutes and sections of statutes; the EPA expects that states 

and sources will take advantage of available flexibilities as 

appropriate, but will comply with all relevant legal 

requirements.
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both rules may regulate or affect the disposal of coal 

combustion wastes to and from surface impoundments at power 

plants.323 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.324

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 

fossil-fired EGUs. 

 

323 See: Federal Register Vol. 78, No. 110; June 7, 2013. Page 

34441. 

324 [We could include some or all of the following modified 

language from proposed the SE ELG rule as a footnote:] 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 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. 
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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 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 
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intends to address the designations for all other areas in 

separate actions in the future325. 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 

 

325 The EPA has developed a comprehensive implementation 

strategy for these future actions that focuses resources on 

identifying and addressing unhealthy levels of SO2 in areas where 

people are most likely to be exposed to violations of the 

standard. The strategy is available at: 

http://www.epa.gov/airquality/sulfurdioxide/implement.html.
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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 

today’s 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 Action326

 

326 The 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 
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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 co-benefits through reductions of SO2, PM2.5 and NOx 

that will have direct public health benefits by lowering ambient 

levels of these pollutants and ozone. Tables 9 and 10 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 9 – 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 2,161 1,476 1,559 212

Proposed 

Guidelines 1,790 1,184 1,213 156

 

that are more cost effective for their particular state or 

choose approaches that shift the balance of co-benefits and 

impacts to match broader state priorities. 
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 Emission 

Reductions 371 292 345 56

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 209

Proposed 

Guidelines 1,730 1,120 1,166 150

Emission 

Reductions 501 395 421 59

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 198

Proposed 

Guidelines 1,711 1,106 1,131 144

Emission 

Reductions 545 424 407 54

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 212

Proposed 

Guidelines 1,777 1,140 1,191 154

Emission 

Reductions 383 335 367 58

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 209

Proposed 

Guidelines 1,724 1,090 1,151 145

Emission 

 Reductions 506 425 436 63

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 198

Proposed 

Guidelines 1,701 1,059 1,109 142

Emission 

Reductions 555 471 428 56

Source: Integrated Planning Model, 2014. 

Table 10 - 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

Emissions 

Reductions 283 244 268 

46
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2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 209

Option 2 1,862 1,218 1,279 165

Emissions 

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

Emissions 

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

Emissions 

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 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 re-dispatch (building block 2) would result in overall CO2

emission reductions of approximately 22 percent in 2020 
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(compared to 2005 emissions and 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 coal-fired EGU retirements in 2020 (compared to 46 – 

49 GW for the four-block 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 fourblock 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 two-block approach and 20 – 22 GW 
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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 two-block 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 $53 
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billion in 2030 (2011$ 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.327 

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 

 

327 Note that the health co-benefits and net benefits for the 

proposed Option 1 include PM co-benefits 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. 
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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 
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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, 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.328 The DOI Solicitor concluded that where the effect 

 

328 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the 

Interior re: “Guidance on the Applicability of the Endangered 
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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 9 above), the EPA evaluated larger 

reductions in assessing this same issue in the context of the 

light duty vehicle GHG emission standards for model years 2012-

2016 and 2017-2025. There the agency projected emission 

reductions roughly double and four times those projected here 

over the lifetimes of the model years in question329 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 

 

Species Act’s Consultation Requirements to Proposed Actions 

Involving the Emission of Greenhouse Gases” (Oct. 3, 2008). 

329 See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at 

62894 Table III-68 (Oct. 15, 2012). 
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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 today’s 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 
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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 
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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 
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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 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 

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 
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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 demandside energy efficiency. The compliance assumptions – and, 

therefore, the projected compliance costs - set forth in this 

analysis are illustrative in nature and do not represent the 

full suite of compliance flexibilities states may ultimately 

pursue. 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. 
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 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 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 
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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. 
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 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 
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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 

benefit-cost 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. 
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 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, 

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 job-years 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 
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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 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 
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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 cobenefits 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 
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estimated for this rule at all discount rates and additional 

analysis years is provided in Tables 11 through 16 of this 

preamble. 

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 
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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 
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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 cobenefits 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$) using a 3 percent 

discount rate (model average). Table 17 shows the climate 

benefits, health co-benefits, cost and net benefits for Option 1 

in 2020 for state and regional compliance approaches. Table 18 

shows similar estimates for 2030. 
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 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 
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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 17—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR PROPOSED OPTION 1 IN 2020a

[Billions of 2011$] 

Option 1 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

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 
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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 

a

 All estimates are for 2020, and are rounded to two significant 

figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to 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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 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 
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not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

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. 

e

 The 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 18—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR PROPOSED OPTION 1 IN 2030a

[Billions of 2011$] 

Option 1 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

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 
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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 

a

 All estimates are for 2030, and are rounded to two significant 

figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to 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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 
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regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

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. 

e

 The 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 19 and 20. As these tables reflect, net 

benefits in 2020 are estimated to be $22 to $40 billion (3 

percent discount rate) and $21 to $34 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 $55 billion (3 

percent discount rate) and $29 billion to $51 billion (7 percent 

discount rate) assuming a regional compliance approach and $30 

billion to $52 billion (3 percent discount rate) and $28 billion 

to $48 billion (7 percent discount rate) assuming a state 

compliance approach. 
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 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 co-benefits 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 19 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR OPTION 2 IN 2020a

[Billions of 2011$] 

Option 2 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

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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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 

a

 All estimates are for 2020, and are rounded to two significant 

figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to 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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 90 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 
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regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

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. 

e

 The 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 20 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR OPTION 2 IN 2025a 

[Billions of 2011$] 

Option 2 Regional Compliance Approach 

 3% Discount rate 7% Discount rate 

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 
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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 

a

 All estimates are for 2025, and are rounded to two significant 

figures, so figures may not sum. 

b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to 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. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 
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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. 

d Total 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. 

e

 The 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 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 
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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 
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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. 
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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 [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB 

is best assured of having its full effect if OMB receives it by 

[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The final rule will respond to any OMB or public comments on the 

information collection requirements contained in this proposal. 

C. Regulatory Flexibility Act 
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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 19 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 21. Potentially Regulated Categories and Entitiesa

 
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Category NAICS 

Code 

Examples of Potentially Regulated 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units. 

State/Local 

Government 

 

221112b

 

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). 

b

 State 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 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 
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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, 
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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 
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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, EPA may not issue an action 

that has federalism implications, that imposes substantial 
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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 
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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.
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A detailed Federalism Summary Impact Statement (FSIS) 

describing the most pressing issues raised in pre-proposal 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 
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of three coal-fired EGUs and one natural gas-fired 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 
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country330 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 

 

330 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands, the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility. 
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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 multistate 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) 
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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 co-benefit, 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 
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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 (Public Law No. 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 

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 
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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).331 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 

 

331 “Endangerment and Cause or Contribute Findings for Greenhouse 

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

66,496 (Dec. 15, 2009) (“Endangerment Finding”). 
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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 climate-related 

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 
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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 fuelfired 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,332 the 

EPA identified persons with lower socioeconomic status as an atrisk 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 

 

332 “National Ambient Air Quality Standards for Particulate 

Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 
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nutritional deficiencies, which can increase this population’s 

risk to PM-related and ozone-related effects.333 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 

 

333 U.S. Environmental Protection Agency (U.S. EPA). 2009. 

Integrated Science Assessment for Particulate Matter (Final 

Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division. December. Available on the Internet 

at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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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 increased utilization of other, 

unmodified EGUs with relatively low GHG emissions per unit of 

electrical output, in particular high efficiency gas-fired EGUs. 

Because such EGUs would not have been modified physically nor 
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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 
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because the impacts due to HAP emissions from such units are 

negligible based on the results of the study documented in the 

utility RTC.” 65 FR 79831. 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, 
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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 peerreviewed studies and data that assess effects of exposure to the 

pollutants addressed by this proposal. 

XII. Statutory Authority 
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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)). 
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Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units 

Page 607 of 648

List of Subjects in 40 CFR Part 60 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements. 

___________________ 

Dated: 

____________________ 

Gina McCarthy, 

Administrator. 

 
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For the reasons stated in the preamble, title 40, chapter I, 

part 60 of the Code of the Federal Regulations is proposed to be 

amended as follows: 

1. Section 60.27 is amended by revising paragraph (b) to read as 

follows: 

* * * * * 

(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. 

* * * * * 

2. Part 60 is amended by adding 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 my state 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? 
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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? 

60.5765 What are the state rate-based CO2 emission performance 

goals? 

60.5770 What is the procedure for converting my state ratebased CO2 emission performance goal to a mass-based 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? 

Introduction 

§ 60.5700 What is the purpose of this subpart?
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 This subpart establishes emission guidelines and approval 

criteria for state plans that establish standards of performance 

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 gases 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 
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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 paragraph § 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. 
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§ 60.5725 In lieu of a state plan submittal, are there other 

acceptable options for a state to meet its section 111(d) 

obligations? 

 No. 

§ 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. 
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State Plan 

§ 60.5740 What must I include in my state plan? 

(a) You must include the elements described in paragraphs 

(a)(1) through (a)(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 (i) must be equivalent to 

or better than the levels of the rate-based CO2 emission 
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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. 

(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 
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together, sufficiently protective to meet the state emissions 

performance level. 

(6) A demonstration that each emission standard is 

quantifiable, non-duplicative, 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 section (a)(3)(iii), 

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. 
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(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); 

(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. 
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(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) 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). States may submit a multi-state plan 

that: 

(1) Demonstrates CO2 emission performance jointly for all 

affected entities in all states participating in the multi-state 

plan, as follows: 

(i) For states demonstrating performance based on the CO2

emission rate, the level of performance identified in the multistate 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 
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(ii) For states demonstrating performance based on mass CO2

emissions, the level of performance identified in the multistate 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. 

(2) Assigns 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)-(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). 
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 (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 [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]; 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). 

(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. 
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(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 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; 
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(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 multistate 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. 
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(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 single-state 

plan, or June 30, 2018, for a multi-state 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). 

§ 60.5765 What are the state rate-based CO2 emissions performance 

goals? 

(a) The annual average state rate-based 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 ratebased CO2 emission performance goal may be converted to a massbased emission performance goal according to § 60.5770. 

§ 60.5770 What is the procedure for converting my state ratebased CO2 emissions performance goal to a mass-based 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 
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period, and include a description of the analytic process, 

tools, methods, and assumptions used to convert from the ratebased goal for the state identified in Table 1 of this Subpart 

to an equivalent mass-based goal. The conversion process must 

include following requirements: 

(b) 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). 

(c) The material supporting the conversion of the ratebased goal, including results, data, and descriptions, must be 

include in a state plan according to § 60.5740(a)(11). 

(d) 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. 

§ 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 
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under the plan. 

(c) For the interim performance period of 2020-2029 your 

state must meet the requirements in paragraphs (c)(1) and (c)(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 section and section § 60.5740 in your state’s annual 
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report required in section § 60.5815. 

§ 60.5780 What emissions 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)-(f). 

(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 non-duplicative 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 
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standard in an approved plan revision, or the state demonstrates 

in an approved plan revision that the emissions 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 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) – (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 
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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 
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turbine that meets the relevant applicability conditions 

specified in paragraphs (b)(1) or (a)(2) of this section. 

(1) A steam generating unit or IGCC that has a base load 

rating greater than 73 MW (250MMBtu/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 netelectric 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 netelectrical 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 

1) those that are subject to subpart TTTT as a result of 

commencing construction or reconstruction after the subpart TTTT 

applicability date and 2) those subject to subpart TTTT as a 
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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). 

(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 (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, 
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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. 
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(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 (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 carbonbased F-factors (Fc) using Equation F-7b in section 3.3.6 of 

appendix F to part 75 of this chapter, and may use these Fc

values in the emissions calculations instead of using the 

default Fc values in the Equation G-4 nomenclature. 
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(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). 
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(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 to the delegated 

authority all hourly CO2 emissions and all hourly net electric 
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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. 
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(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. 
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(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. 
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(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. 

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. 
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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 solvent-refined coal, gasified coal 

(not meeting the definition of natural gas), coal-oil mixtures, 

and coal-water mixtures are included in this definition for the 

purposes of this subpart. 

Combined cycle 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 steam-generating unit or stationary combustion 
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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 massbased plan, and shall be no greater than a one year period for a 

rate-based 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. 
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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, coke-oven gas, synthetic gas, 

and gasified coal. 

 Heat recovery steam generating unit (HRSG) means a unit in 

which hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

 Integrated gasification combined cycle facility or IGCC 
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facility means a combined cycle facility that is designed to 

burn fuels containing 50 percent (by heat input) or more solidderived fuel not meeting the definition of natural gas plus any 

integrated equipment that provides electricity or useful thermal 

output to either the affected facility or auxiliary equipment. 

The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit during operation. 

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at 

ISO conditions and includes, but is not limited to, distillate 

oil and residual oil. 

Mechanical output means the useful mechanical energy that 

is not used to operate the affected facility, generate 

electricity and/or thermal output, or to enhance the performance 

of the affected facility. Mechanical energy measured in 

horsepower hour should be converted into MWh by multiplying it 

by 745.7 then dividing by 1,000,000. 

Natural gas means a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 
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and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

state under ISO conditions. In addition, natural gas contains 

20.0 grains or less of total sulfur per 100 standard cubic feet. 

Finally, natural gas does not include the following gaseous 

fuels: landfill gas, digester gas, refinery gas, sour gas, blast 

furnace gas, coal-derived gas, producer gas, coke oven gas, or 

any gaseous fuel produced in a process which might result in 

highly variable sulfur content or heating value. 

Net-electric output means the amount of gross generation 

the generator(s) produce (including, but not limited to, output 

from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the 

electricity used to operate the plant (i.e., auxiliary loads); 

such uses include fuel handling equipment, pumps, fans, 

pollution control equipment, other electricity needs, and 

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 
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performance of the unit (e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power facilities where at least 

20.0 percent of the total gross 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 (25o C, 77 oF)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy 

of water at SATP conditions is 50 Btu/lb.
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Stationary combustion turbine means all equipment, 

including but not limited to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, control systems (except 

emissions control equipment), heat recovery system, fuel 

compressor, heater, and/or pump, post-combustion emissions 

control technology, and any ancillary components and subcomponents comprising any simple cycle stationary combustion 

turbine, any combined cycle combustion turbine, and any combined 

heat and power combustion turbine based system plus any 

integrated equipment that provides electricity or useful thermal 

output to the combustion turbine engine, heat recovery system or 

auxiliary equipment. Stationary means that the combustion 

turbine is not self-propelled or intended to be propelled while 

performing its function. It may, however, be mounted on a 

vehicle for portability. If a stationary combustion turbine 

burns any solid fuel directly it is considered a steam 

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 
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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 
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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 
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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 
***E.O. 12866 Review – Revised Version – Do Not Cite, Quote or Release During 

Review*** 

Page 648 of 648

1,748 1,620 

Wisconsin 

1,281 

 

1,203 

Wyoming 

1,808 

 

1,714